Corrosion inhibitor systems for low, moderate and high temperature fluids and methods for making and using same

ABSTRACT

A corrosion control system is disclosed including an anionic oxygen inhibitor, a cationic acid inhibitor or dispersant, and a noxious species inhibitor or scavenger for use in a fluid in contact with a metallic surface at low temperature, moderate temperature and especially at high temperature. A drilling fluid, a completion fluid, a production fluid and a geothermal fluid including an effective amount of the corrosion control system is also disclosed as well as methods for making and using same.

RELATED APPLICATIONS

This application claims the benefit of and priority to U.S. Ser. No.11/066,600, filed 25 Feb. 2005 (Feb. 25, 2005).

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a corrosion inhibitor system for low,moderate and/or high temperature applications such as geothermalapplications, oil field applications, power plant applications or otherlow, moderate and high temperature applications where scale andcorrosion are problems and to methods for making and using same.

More particularly, the present invention relates to a scale andcorrosion inhibitor system for low, moderate, and high temperatureapplications such as geothermal applications, oil field applications,power plant applications or other low, moderate and/or high temperatureapplications where scale and corrosion are problems and to methods formaking and using same, where the system includes a scale inhibitor, anoxious species inhibitor or scavenger and an acid inhibitor orscavenger.

2. Description of the Related Art

Scale and corrosion are longstanding problems encountered in manyindustries. Scale and corrosion are significant problems in many hightemperature applications such as geothermal fluid production, powerplant circulating fluids, oil fluid circulation and production or otherapplication where temperatures are involved and scale and corrosion arelimit the life time of equipment.

Although many corrosion and scale inhibitors are known and used in hightemperature application, many of these systems have limitations and donot provide the type of protection to allow significant extend equipmentlife time. Thus, there is a need in the art for corrosion and scaleinhibition system that is effective a low, moderate and hightemperatures and can significantly extend the service life of equipmentexposed to corrosive low, moderate or temperature environments.

DEFINITIONS USED IN THE INVENTION

An over-balanced pressure drilling fluid means a drilling fluid having ahydrostatic density (pressure) higher than a formation density(pressure). For example, if a known formation at 10,000 ft (TrueVertical Depth—TVD) has a hydrostatic pressure of 5,000 psi or 9.6lbm/gal, an over-balanced drilling fluid would have a hydrostaticpressure greater than 9.6 lbm/gal.

An under-balanced and/or managed pressure drilling fluid means adrilling fluid having a hydrostatic density (pressure) lower or equal toa formation density (pressure). For example, if a known formation at10,000 ft (True Vertical Depth—TVD) has a hydrostatic pressure of 5,000psi or 9.6 lbm/gal, an under-balanced drilling fluid would have ahydrostatic pressure less than or equal to 9.6 lbm/gal. Mostunder-balanced and/or managed pressure drilling fluids include at leasta density reduction additive. Other additive many include a corrosioninhibitor, a pH modifier and a shale inhibitor.

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description of the presentinvention.

The term “amphoteric” refers to surfactants that have both positive andnegative charges. The net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution.

The term “anionic” refers to those viscoelastic surfactants that possessa net negative charge.

The abbreviation “RPM” refers to relative permeability modifiers.

The term “surfactant” refers to a soluble, or partially soluble compoundthat reduces the surface tension of liquids, or reduces inter-facialtension between two liquids, or a liquid and a solid by congregating andorienting itself at these interfaces.

The term “viscoelastic” refers to those viscous fluids having elasticproperties, i.e., the liquid at least partially returns to its originalform when an applied stress is released.

The phrase “viscoelastic surfactants” or “VES” refers to that class ofcompounds which can form micelles (spherulitic, anisometric, lamellar,or liquid crystal) in the presence of counter ions in aqueous solutions,thereby imparting viscosity to the fluid. Anisometric micelles inparticular are preferred, as their behavior in solution most closelyresembles that of a polymer.

The abbreviation “VAS” refers to a Viscoelastic Anionic Surfactant,useful for fracturing operations and frac packing. As discussed herein,they have an anionic nature with preferred counterions of potassium,ammonium, sodium, calcium or magnesium.

A sulfur scavenger is compounds that convert noxious sulfur-containingcompounds such as hydrogen sulfide into less noxious sulfur-containingcompounds or into benign sulfur-containing compounds.

A triazine is a six membered ring including nitrogen atom at adjacentpositions of the six membered ring.

The term low temperature means a temperature between about 100° F. andabout 250° F.

The term moderate temperature means a temperature between about 250° F.and about 450° F.

The term high temperature means a temperature between about 450° F. andabout 600° F.

SUMMARY OF THE INVENTION Corrosion Control Systems

The present invention provides a corrosion control system including ananionic oxygen inhibitor, a cationic acid inhibitor or dispersant, and anoxious species inhibitor or scavenger.

The present invention provides a corrosion control system including ananionic phosphate ester oxygen inhibitor, a cationic acid inhibitor ordispersant, and a noxious species inhibitor or scavenger.

The present invention also provides a corrosion control system includinga phosphate ester, a cationic dispersant, a sulfur scavenger andembrittlement inhibitor.

The present invention provides a corrosion control system including asalt of a glycol phosphate ester, a quinoline quat surfactant type acidinhibitor, and a formaldehyde-amine type sulfur scavenger andembrittlement inhibitor.

The present invention also provides a corrosion control system includinga salt of a glycol phosphate ester, a quinoline quat surfactant typeacid inhibitor, and a formaldehyde monoalkylanol amine type sulfurscavenger and embrittlement inhibitor.

The present invention provides a corrosion control system including asalt of a glycol phosphate ester, quinoline quat surfactant type acidinhibitor, a triazine type sulfur scavenger and embrittlement inhibitor.

The present invention also provides a corrosion control system includinga salt of a glycol phosphate ester, quinoline quat surfactant type acidinhibitor, a formaldehyde sterically hindered amine type sulfurscavenger and embrittlement inhibitor.

Methods of Using the Corrosion Control Systems

The present invention provides a method including the step of adding ona continuous, semi-continuous, periodic, intermittent or discrete basisto a fluid a corrosion control system of this invention at aconcentration sufficient to reduce corrosion of metal in contact withthe fluid.

The present invention also provides a method including the step ofadding on a continuous, semi-continuous, periodic, intermittent ordiscrete basis to a high temperature fluid a corrosion control system ofthis invention at a concentration sufficient to reduce corrosion incontact with the high temperature fluid.

The present invention provides a method including the step of adding ona continuous, semi-continuous, periodic, intermittent or discrete basisto a high temperature geothermal fluid a corrosion control system ofthis invention at a concentration sufficient to reduce corrosion incontact with the high temperature geothermal fluid.

The present invention also provides a method including the step ofadding on a continuous, semi-continuous, periodic, intermittent ordiscrete basis to a drilling fluid a corrosion control system of thisinvention at a concentration sufficient to reduce corrosion in contactwith the drilling fluid.

The present invention also provides a method including the step ofadding on a continuous, semi-continuous, periodic, intermittent ordiscrete basis to a high temperature drilling fluid a corrosion controlsystem of this invention at a concentration sufficient to reducecorrosion in contact with the high temperature drilling fluid.

The present invention also provides a method including the step ofadding on a continuous, semi-continuous, periodic, intermittent ordiscrete basis to a fracturing fluid a corrosion control system of thisinvention at a concentration sufficient to reduce corrosion in contactwith the drilling fluid.

The present invention also provides a method including the step ofadding on a continuous, semi-continuous, periodic, intermittent ordiscrete basis to a high temperature fracturing fluid a corrosioncontrol system of this invention at a concentration sufficient to reducecorrosion in contact with the high temperature drilling fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the followingdetailed description together with the appended illustrative drawings inwhich like elements are numbered the same:

FIGS. 1A&B depict plots of corrosion rate and imbalance for severalC-100 and C-119 compositions in 3.5% Seawater, respectively;

FIG. 1C depict photographs of an electrode before exposure to acorrosive environment (left) and after exposure to the corrosiveenvironment (right);

FIG. 1D depicts a photograph of a treating solution into which theelectrodes of FIG. 1C are placed and treated at a desired temperature;

FIGS. 2A-F depict coupons from Tests 3-5 are shown both pre-acid wash,FIGS. 2A, C and E, and post acid wash, FIGS. 2B, D and F;

FIGS. 3A&B depict plots of corrosion rate and imbalance for severalcompositions of this invention in 3.5% Seawater, respectively;

FIG. 3C depicts a photograph of the solutions of in Tests 7-12;

FIG. 3D depicts a photograph of the electrodes that were placed in thesolution of Test 7 and Test 8;

FIG. 3E depicts a photograph of the electrodes that were placed in thesolution of Test 9 and Test 10;

FIG. 3F depicts a photograph of the electrodes that were placed in thesolution of Test 11 and Test 12;

FIGS. 4A&B depicts a photograph of the coupons from Tests 13-15 pre-acidwashed and post acid wash, respectively;

FIGS. 4C&D depicts a photograph of the coupons from Tests 16-18 pre-acidwash and post acid wash, respectively;

FIGS. 4E&F depicts a photograph of the solutions of Tests 13-15 andTests 16-18, respectively;

FIG. 5A depicts a photograph of the Test 19 solutions of Example 13after 24 hours in the autoclave;

FIGS. 5B-D depict coupons 11-13 immediately upon removal from the Test19 solutions, prior to acid washing and after acid washing,respectively;

FIG. 5E depicts the Test 20 solutions of Example 14 after 24 hours inthe autoclave;

FIGS. 5F-H depict the coupons 14-16 immediately upon removal from theTest 20 solutions, prior to acid washing and after acid washing,respectively;

FIG. 5I depicts the Test 21 solutions of Example 15 after 24 hours inthe autoclave;

FIGS. 5J-L depict the coupons 17-19 immediately upon removal from theTest 21 solutions, prior to acid washing and after acid washing,respectively;

FIG. 5M depicts the Test 22 solutions of Example 16 after 24 hours inthe autoclave;

FIG. 5N-P depicts the coupons 20-22 immediately upon removal from theTest 22 solutions, prior to acid washing and after acid washing,respectively;

FIG. 5Q, the Test 23 solutions of Example 17 are shown after 24 hours inthe autoclave;

FIG. 5R-T, the coupons 23-25 are shown immediately upon removal from theTest 23 solutions, prior to acid washing and after acid washing,respectively;

FIG. 5U, the Test 24 solutions of Blank are shown after 24 hours in theautoclave;

FIG. 5V-X, the coupons 26-28 are shown immediately upon removal from theBlank solutions, prior to acid washing and after acid washing,respectively;

FIG. 5Y, the Test 25 solutions of Blank with 3.5 wt. % Seawater areshown after 24 hours in the autoclave; and

FIGS. 5Z, AA & AB, the coupons 29-30 are shown immediately upon removalfrom the Test 25 solutions, prior to acid washing and after acidwashing, respectively.

DETAILED DESCRIPTION OF THE INVENTION

The inventor has found that a new and stable corrosion inhibitor systemcan be prepared that is finds applications in low, moderate and hightemperature applications such as geothermal applications, oil fieldapplications, power plant applications or other low, moderate and/orhigh temperature applications. The corrosion inhibitor systems includesa combination of ingredients hithertobefore considered to beincapability, which combine do form a composition that has remarkablescale and corrosion inhibitory properties. The inventors have found thatthe corrosion control system of this invention can be used in all typeof drilling fluids, completion fluids or production fluids includingover-balanced and under-balanced fluids, in all type of geothermalsystems, in one phase (water or oil) or mixed phase systems (e.g.,biphasic system such as oil and water or triphasic systems composed ofthree distinct liquid phases) or in any other type of environment wherecorrosion control is a problem. In under-balanced applications, theagent that reduces the mass of the fluid can be air, nitrogen, carbondioxide, membrane nitrogen or mixtures or combinations thereof.

The present invention broadly relates to a method for protectingmetallic equipment from corrosion including the step of adding to afluid in contact with the equipment a composition including an anionicoxygen inhibitor, a cationic acid inhibitor, and a noxious species andembrittlement inhibitor, where the composition protects the metallicequipment from corrosion and pitting at low, moderate and hightemperatures. The compositions finds application in temperatureapplications in a range between about 250° F. and about 600° F.

The present invention broadly relates to a method for protectingmetallic equipment from corrosion including the step of adding to ageothermal fluid in contact with the equipment a composition includingan anionic oxygen inhibitor, a cationic acid inhibitor, and a noxiousspecies and embrittlement inhibitor, where the composition protects themetallic equipment from corrosion and pitting at moderate and hightemperatures. The compositions finds application in moderate to hightemperature applications in a range between about 250° F. and about 600°F.

The present invention broadly relates to a method for protectingmetallic equipment from corrosion including the step of adding to ageothermal fluid in contact with the equipment a composition includingan anionic oxygen inhibitor, a cationic acid inhibitor, and a noxiousspecies and embrittlement inhibitor, where the composition protects themetallic equipment from corrosion and pitting at high temperatures. Thecompositions finds application in high temperature applications fromabout 450° F. to about 600° F.

The present invention also broadly relates to a composition including ananionic oxygen inhibitor, a cationic acid inhibitor, and a noxiousspecies and embrittlement inhibitor, where the composition protects themetallic equipment from corrosion and pitting at low, moderate and hightemperatures.

The present invention also broadly relates to an aqueous-based,under-balanced or managed pressure drilling fluid including an effectiveamount of a composition including an anionic oxygen inhibitor, acationic acid inhibitor, and a noxious species and embrittlementinhibitor, where the effective amount of the composition is sufficientto reduce corrosion and pitting of metal in contact with the drillingfluid during under-balanced drilling operations at low, moderate andhigh temperatures. The under-balanced drilling fluid includes at leastwater, a density reduction additive, and an effective amount of thecomposition. The drilling fluid can also include other additives such asa pH modifier, a CO₂ scavenger, a reactive shale and/or clay inhibitor,or combination thereof.

In one preferred embodiment of the corrosion control system of theinvention, the corrosion control system includes from about 1.25 ppm toabout 5 wt. % of a salt of a phosphate ester scale inhibitor, from about0.25 wt. % to about 10 wt. % a cationic acid corrosion inhibitor, andfrom about 0.1 wt. % up to about a 10:1 ratio of a noxious sulfurspecies scavenger based on a concentration of the noxious sulfur speciessuch as H₂S in ppm in the fluid to be treated and a balance beingdeionized water. Optionally, the composition includes lime, a limeslurry, or hot lime from about 1 to 10 lbs per barrel, i.e., about 3.5lbs per 350 lbs of composition or about 1 wt. %.

In another preferred embodiment of the corrosion control system of theinvention, the corrosion control system includes from about 1.25 ppm toabout 5 wt. % of a salt of a phosphate ester scale inhibitor, from about0.25 wt. % to about 10 wt. % a cationic acid corrosion inhibitor, andfrom about 1.0 wt. % up to a balance of the composition in placed ofwater of a sulfur scavenger, where the sulfur scavenger comprises asolution of the sulfur scavenger in a solvent such as water. Thesolution can be from about 25 wt. % of the solvent to about 75 wt. % ofthe sulfur scavenger to about 75 wt. % of the solvent to about 25 wt. %of the sulfur scavenger. Optionally, the composition includes lime, alime slurry, or hot lime from about 1 to 10 lbs per barrel, i.e., about3.5 lbs per 350 lbs of composition or about 1 wt. %.

In another preferred embodiment of the corrosion control system of theinvention, the corrosion control system includes from about 1.25 ppm toabout 5 wt. % of a salt of a phosphate ester scale inhibitor, from about0.25 wt. % to about 10 wt. % a cationic acid corrosion inhibitor, andfrom about 1.0 wt. % up to a balance of the composition in placed ofwater of a first sulfur scavenger, from about 0.1 wt. % up to 10:1 basedon a concentration of H₂S in ppm in the fluid to be treated of a secondsulfur scavenger and a balance being deionized water, if the water isrequired. Of course, other solvent systems can be used as well such asan alcohol, an alcohol-water mixture, a glycol, a glycol-water mixtureor other similar solvent system. Optionally, the composition includeslime, a lime slurry, or hot lime from about 1 to 10 lbs per barrel,i.e., about 3.5 lbs per 350 lbs of composition or about 1 wt. %.

In another preferred embodiment of the corrosion control system of theinvention, the corrosion control system includes a reaction product offrom about 1.25 ppm to about 5 wt. % of a salt of a phosphate esterscale inhibitor, from about 0.25 wt. % to about 10 wt. % a cationic acidcorrosion inhibitor, and from about 0.1 wt. % up to about a 10:1 ratioof a noxious sulfur species scavenger based on a concentration of thenoxious sulfur species such as H₂S in ppm in the fluid to be treated anda balance being deionized water and optionally, lime, a lime slurry, orhot lime from about 1 to 10 lbs per barrel, i.e., about 3.5 lbs per 350lbs of composition or about 1 wt. % heated to a temperature of at least120° F. In another embodiment, the above composition is heated to atemperature of at least 200° F. In another embodiment, the abovecomposition is heated to a temperature of at least 300° F. In anotherembodiment, the above composition is heated to a temperature of at least400° F. In another embodiment, the above composition is heated to atemperature of at least 450° F. In another embodiment, the abovecomposition is heated to a temperature of at least 500° F.

In another preferred embodiment of the corrosion control system of theinvention, the corrosion control system includes a reaction product offrom about 1.25 ppm to about 5 wt. % of a salt of a phosphate esterscale inhibitor, from about 0.25 wt. % to about 10 wt. % a cationic acidcorrosion inhibitor, and from about 1.0 wt. % up to a balance of thecomposition in placed of water of a sulfur scavenger, where the sulfurscavenger comprises a solution of the sulfur scavenger in a solvent suchas water. The solution can be from about 25 wt. % of the solvent toabout 75 wt. % of the sulfur scavenger to about 75 wt. % of the solventto about 25 wt. % of the sulfur scavenger and optionally, lime, a limeslurry, or hot lime from about 1 to 10 lbs per barrel, i.e., about 3.5lbs per 350 lbs of composition or about 1 wt. % heated to a temperatureof at least 120° F. In another embodiment, the above composition isheated to a temperature of at least 200° F. In another embodiment, theabove composition is heated to a temperature of at least 300° F. Inanother embodiment, the above composition is heated to a temperature ofat least 400° F. In another embodiment, the above composition is heatedto a temperature of at least 450° F. In another embodiment, the abovecomposition is heated to a temperature of at least 500° F.

In another preferred embodiment of the corrosion control system of theinvention, the corrosion control system includes a reaction product offrom about 1.25 ppm to about 5 wt. % of a salt of a phosphate esterscale inhibitor, from about 0.25 wt. % to about 10 wt. % a cationic acidcorrosion inhibitor, and from about 1.0 wt. % up to a balance of thecomposition in placed of water of a first sulfur scavenger, from about0.1 wt. % up to 10:1 based on a concentration of H₂S in ppm in the fluidto be treated of a second sulfur scavenger and a balance being deionizedwater, if the water is required and optionally, lime, a lime slurry, orhot lime from about 1 to 10 lbs per barrel, i.e., about 3.5 lbs per 350lbs of composition or about 1 wt. % heated to a temperature of at least120° F. In another embodiment, the above composition is heated to atemperature of at least 200° F. In another embodiment, the abovecomposition is heated to a temperature of at least 300° F. In anotherembodiment, the above composition is heated to a temperature of at least400° F. In another embodiment, the above composition is heated to atemperature of at least 450° F. In another embodiment, the abovecomposition is heated to a temperature of at least 500° F. Of course,other solvent systems can be used as well such as an alcohol, analcohol-water mixture, a glycol, a glycol-water mixture or other similarsolvent system.

In a preferred embodiment of drilling fluids of this invention, thedrilling fluids are designed for under-balanced or managed pressuredrilling, completion, production or related operations performed in anunder-balanced or managed pressure condition include from about 0.1% v/vto about 10.0% v/v of a foamer or other density reduction additive, fromabout 0.1% v/v to about 5% v/v of a corrosion control system of thisinvention, from about 0.1% v/v to about 10.0% v/v of a choline saltsolution and the remainder being water, where the choline salt solutionis generally about 70 wt. % of the choline salt with remainder beingwater. Generally, the resulting drilling fluid is pH adjusted by theaddition of a sufficient amount of pH modifier to adjust the pH to about10. A preferred embodiment of the drilling fluids of this inventionincludes from about 0.2% v/v to about 5.0% v/v of a foamer or otherdensity reduction additive, from about 0.1% v/v to about 2.0% v/v of acorrosion control system of this invention, from about 0.1% v/v to about5.0% v/v of a choline salt solution and the remainder being water, wherethe choline salt solution is generally about 70 wt. % of the cholinesalt with remainder being water. Another preferred embodiment of thedrilling fluids of this invention includes from about 0.2% v/v to about4.0% v/v of a foamer or other density reduction additive, from about0.1% v/v to about 1.0% v/v of a corrosion control system of thisinvention, from about 0.1% v/v to about 3.0% v/v of a choline saltsolution and the remainder being water, where the choline salt solutionis generally about 70 wt. % of the choline salt with remainder beingwater.

One preferred method of this invention includes the step of adding aneffective amount of a composition of this invention to a fluid incontact with metallic surfaces, where the effective amount is sufficientto reduce acid, noxious species, oxygen or other types of corrosion. Thecompositions are effective in reducing corrosion as much as an order ofmagnitude as compared to corrosion systems not including a phosphateester scale inhibitor, a cationic acid inhibitor and a sulfur scavenger.

Another preferred method of this invention includes the step ofcombining a scale inhibitor, a noxious species inhibitor or scavengerand an acid inhibitor or scavenger and heating the combination to atemperature sufficient to form a high-temperature corrosion controlsystem of this invention. While not meaning to be bound to a giventheory, the inventors speculate that the three components undergo amolecular conversion where the phosphate ester salts react with eitheror both of the other components to form a new, effectivehigh-temperature corrosion control system.

Suitable Reagents for Use in the Invention

Phosphate Ester Salts

Suitable phosphate ester salts for use in this invention include,without limitation, alkali, alkaline earth metal, or transition metalsalts of alkyl phosphate ester, alkoxy phosphate esters, glycolsphosphate esters, alkypolyol phosphate esters or the like or mixture orcombinations thereof. Exemplary examples of glycol phosphate estersinclude, without limitation, ethylene glycol (EG), propylene glycol,butylene glycol, hexylene glycol, trimethylol propane, pentaeryithrol,neopentyl glycol or the like or mixtures or combinations thereof.

Sulfur Scavenger

Suitable sulfur scavengers for use in this invention include, withoutlimitation, amines, aldehyde-amine adducts, triazines, or the like ormixtures or combinations thereof. Exemplary examples of aldehyde-amineadduct type sulfur scavengers include, without limitation, (1)formaldehyde reaction products with primary amines, secondary amines,tertiary amines, primary diamines, secondary diamines, tertiarydiamines, mixed diamines (diamines having mixtures of primary, secondaryand tertiary amines), primary polyamines, secondary polyamines, tertiarypolyamines, mixed polyamines (polyamines having mixtures of primary,secondary and tertiary amines), monoalkanolamines, dialkanol amines andtrialkanol amines; (2) linear or branched alkanal (i.e., RCHO, where Ris a linear or branched alkyl group having between about 1 and about 40carbon atoms or mixtures of carbon atoms and heteroatoms such as Oand/or N) reaction products with primary amines, secondary amines,tertiary amines, primary diamines, secondary diamines, tertiarydiamines, mixed diamines (diamines having mixtures of primary, secondaryand tertiary amines), primary polyamines, secondary polyamines, tertiarypolyamines, mixed polyamines (polyamines having mixtures of primary,secondary and tertiary amines), monoalkanolamines, dialkanol amines andtrialkanol amines; (3) aranals (R′CHO, where R′ is an aryl group havingbetween about 5 and about 40 carbon atoms and heteroatoms such as Oand/or N) reaction products with primary amines, secondary amines,tertiary amines, primary diamines, secondary diamines, tertiarydiamines, mixed diamines (diamines having mixtures of primary, secondaryand tertiary amines), primary polyamines, secondary polyamines, tertiarypolyamines, mixed polyamines (polyamines having mixtures of primary,secondary and tertiary amines), monoalkanolamines, dialkanol amines andtrialkanol amines; (4) alkaranals (R″CHO, where R″ is an alkylated arylgroup having between about 6 and about 60 carbon atoms and heteroatomssuch as O and/or N) reaction products with primary amines, secondaryamines, tertiary amines, primary diamines, secondary diamines, tertiarydiamines, mixed diamines (diamines having mixtures of primary, secondaryand tertiary amines), primary polyamines, secondary polyamines, tertiarypolyamines, mixed polyamines (polyamines having mixtures of primary,secondary and tertiary amines), monoalkanolamines, dialkanol amines andtrialkanol amines; (5) aralkanals (R″CHO, where R″ is an arylsubstituted linear or branched alkyl group having between about 6 andabout 60 carbon atoms and heteroatoms such as O and/or N) reactionproducts with primary amines, secondary amines, tertiary amines, primarydiamines, secondary diamines, tertiary diamines, mixed diamines(diamines having mixtures of primary, secondary and tertiary amines),primary polyamines, secondary polyamines, tertiary polyamines, mixedpolyamines (polyamines having mixtures of primary, secondary andtertiary amines), monoalkanolamines, dialkanol amines and trialkanolamines, and (6) mixtures or combinations thereof. It should berecognized that under certain reaction conditions, the reaction mixturemay include triazines in minor amount or as substantially the onlyreaction product (greater than 90 wt. % of the product), while underother conditions the reaction product can be monomeric, oligomeric,polymeric, or mixtures or combinations thereof. Other sulfur scavengersare disclosed in WO04/043038, US2003-0089641, GB2397306, U.S. patentapplication Ser. Nos. 10/754,487, 10/839,734, and 10/734,600,incorporated herein by reference.

Shale Inhibitors

Suitable choline salts or 2-hydroxyethyl trimethylammonium salts for usein this invention include, without limitation, choline organiccounterion salts, choline inorganic counterion salts, or mixture orcombinations thereof. Preferred choline counterion salts of thisinvention include, without limitation, choline or 2-hydroxyethyltrimethylammonium halide counterion salts, carboxylate counterion salts,nitrogen oxide counterion salts, phosphorus oxide counterion salts,sulfur oxide counterion salts, halogen oxide counterion salts, metaloxide counterion salts, carbon oxide counterion salts, boron oxidecounterion salts, perfluoro counterion salts, hydrogen oxide counterionsalts or mixtures or combinations thereof. Other examples can be foundin U.S. patent application Ser. No. 10/999,796, incorporated herein byreference.

Exemplary examples of choline halide counterion salts including cholinefluoride, choline chloride, choline bromide, choline iodide, or mixturesor combinations thereof.

Suitable choline carboxylate counterion salts include, withoutlimitation, choline carboxylate counterion salts where the carboxylatecounterion is of the general formula R¹COO⁻, where R¹ is an alkyl group,alkenyl group, alkynyl group, an aryl group, an alkaryl group, anaralkyl group, alkenylaryl group, aralkenyl group, alkynylaryl group,aralkynyl group hetero atom analogs, where the hetero atom is selectedfrom the group consisting of boron, nitrogen, oxygen, fluorine,phosphorus, sulfur, chlorine, bromine, iodine, and mixture orcombinations thereof, or mixtures or combinations thereof. Anon-exhaustive list of exemplary examples of choline carboxylatecounterion salts include choline formate, choline acetate, cholinepropanate, choline butanate, cholide pentanate, choline hexanate,choline heptanate, choline octanate, choline nonanate, choline decanate,choline undecanate, choline dodecanate, and choline higher linearcarboxylate salts, choline benzoate, choline salicylate, other cholinearomatic carboxylate counterion salts, choline stearate, choline oleate,other choline fatty acid counterion salts, choline glyolate, cholinelactate, choline hydroxyl acetate, choline citrate, other cholinehydroxylated carboxylates counterion salts, choline aconitate, cholinecyanurate, choline oxalate, choline tartarate, choline itaconate, othercholine di, tri and polycarboxylate counterion salts, cholinetrichloroacetate, choline trifluoroacetate, other choline halogenatedcarboxylate counterion salts, or mixture or combinations thereof. Othercholine carboxylate counterion salts useful in the drilling fluids ofthis invention include choline amino acid counterion salts includingcholine salts of all naturally occurring and synthetic amino acids suchas alanine, arginine, asparagine, aspartic acid, cysteine, glutamine,glutamic acid, glycine, histidine, isoleucine, leucine, lysine,methionine, phenylalanine, proline, serine, threonine, tryptophan,tyrosine, valine, (R)-Boc-4-(4-pyridyl)-β-Homoala-OH purum,(S)-Boc-4-(4-pyridyl)-β-Homoala-OH purum,(R)-Boc-4-trifluoromethyl-β-Homophe-OH purum,(S)-Fmoc-3-trifluoromethyl-β-Homophe-OH purum,(S)-Boc-3-trifluoromethyl-β-Homophe-OH purum,(S)-Boc-2-trifluoromethyl-β-Homophe-OH purum,(S)-Fmoc-4-chloro-β-Homophe-OH purum, (S)-Boc-4-methyl-β-Homophe-OHpurum, 4-(Trifluoromethyl)-L-phenylalanine purum,2-(Trifluoromethyl)-D-phenylalanine purum,4-(Trifluoromethyl)-D-phenylalanine purum, 3-(2-Pyridyl)-L-alaninepurum, 3-(2-Pyridyl)-L-alanine purum, 3-(3-Pyridyl)-L-alanine purum, ormixtures or combinations thereof or mixtures or combinations of theseamino acid choline salts with other choline salts. Other preferredcarboxylate counterions are counterions formed from a reaction of acarboxylic acid or carboxylate salt with an alkenyl oxide to form acarboxylate polyalkylene oxide alkoxide counterion salt. Preferredalkenyl oxides include ethylene oxide, propylene oxide, butylene oxide,and mixtures and/or combinations thereof.

Exemplary examples of choline nitrogen oxide counterion salts includingcholine nitrate, choline nitrite, choline N_(x)O_(y) counterion salts ormixtures or combinations thereof.

Exemplary examples of choline phosphorus oxide counterion salts includecholine phosphate, choline phosphite, choline hydrogen phosphate,choline dihydrogen phosphate, choline hydrogen phosphite, cholinedihydrogen phosphite, or mixtures or combinations thereof.

Exemplary examples of choline sulfur oxide counterion salts includecholine sulfate, choline hydrogen sulfate, choline persulfate, cholinealkali metal sulfates, choline alkaline earth metal sulfates, cholinesulfonate, choline alkylsulfonates, choline sulfamate (NH₂SO₃ ⁻),choline taurinate (NH₂CH₂CH₂SO₃ ⁻), or mixtures or combinations thereof.

Exemplary examples of choline halogen oxide counterion salts includingcholine chlorate, choline bromate, choline iodate, choline perchlorate,choline perbromate, choline periodate, or mixtures or combinationsthereof.

Exemplary examples of choline metal oxide counterion salts includingcholine dichromate, choline iron citrate, choline iron oxalate, cholineiron sulfate, choline tetrathiocyanatodiamminechromate, cholinetetrathiomolybdate, or mixtures or combinations thereof.

Exemplary examples of choline carbon oxide counterion salts includecholine carbonate, choline bicarbonate, choline alkali carbonates,choline alkaline earth metal carbonates, or mixtures or combinationsthereof.

Exemplary examples of choline boron oxide counterion salts includingcholine borate, tetraphenyl borate, or mixtures or combinations thereof.

Exemplary examples of choline perfluoro counterion salts includingcholine tetrafluoroborate, choline hexafluoroantimonate, cholineheptafluorotantalate(V), choline hexafluorogermanate(IV), cholinehexafluorophsophate, choline hexafluorosilicate, cholinehexafluorotitanate, choline metavanadate, choline metatungstate, cholinemolybdate, choline phosphomolybdate, choline trifluoroacetate, cholinetrifluoromethanesulfonate, or mixtures or combinations thereof.

Exemplary examples of choline hydrogen oxide counterion salts includingcholine hydroxide, choline peroxide, choline superoxide, mixtures orcombinations thereof.

hydroxide reacted with: formic acid; acetic acid; phosphoric acid;hydroxy acetic acid; nitric acid; nitrous acid; poly phos; derivativesof P₂O₅; acid; (acid of glyoxal); sulfuric; all the amino acids (lycine,torine, glycine, etc.); NH₂CH₂CH₂SO₃H; sulfamic; idodic; all the fattyacids; diamethylol proprionic acid; cyclolaucine; phosphorous; boric;proline; benzoic acid; tertiary chloro acetic; fumeric; salicylic;choline derivatives; ethylene oxide; propylene oxide; butylene oxide;epilene chloro hydrine; ethylene chloro hydrine; choline carbonate; andcholine peroxide.

One preferred class of choline salts of this invention is given by thegeneral formula (I):HOCH₂CH₂N⁺(CH₃)₃.R¹COO⁻  (I)where R¹ is an alkyl group, alkenyl group, alkynyl group, an aryl group,an alkaryl group, an aralkyl group, alkenylaryl group, aralkenyl group,alkynylaryl group, aralkynyl group hetero atom analogs, where the heteroatom is selected from the group consisting of boron, nitrogen, oxygen,fluorine, phosphorus, sulfur, chlorine, bromine, iodine, and mixture orcombinations thereof, or mixtures or combinations thereof.

While choline halides have been used in drilling, completion andproduction operations under over-balanced conditions, cholinecarboxylate salts have not been used in such applications. These newanti-swell additives should enjoy broad utility in all conventionaldrilling, completion and/or production fluids.

pH Modifiers

Suitable pH modifiers for use in this invention include, withoutlimitation, alkali hydroxides, alkali carbonates, alkali bicarbonates,alkaline earth metal hydroxides, alkaline earth metal carbonates,alkaline earth metal bicarbonates and mixtures or combinations thereof.Preferred pH modifiers include NaOH, KOH, Ca(OH)₂, CaO, Na₂CO₃, KHCO₃,K₂CO₃, NaHCO₃, MgO, Mg(OH)₂ and combination thereof.

Weight Reducing Agents and Foamers

The weight reducing agents and foamers use for this invention include,without limitation, any weight reducing agent or foamer currentlyavailable or that will be come available during the life time of thispatent application or patent maturing therefrom. Preferred foamers arethose available from Weatherford International, Inc. facility inElmendorf, Tex. Generally, the foamers used in this invention caninclude alone or in any combination an anionic surfactant, a cationicsurfactant, a non-ionic surfactant and a zwitterionic surfactant.Preferred foaming agents includes those disclosed in co-pending U.S.patent application Ser. No. 10/839,734 filed May 5, 2004.

Other Corrosion Inhibitors

Suitable corrosion inhibitor for use in this invention include, withoutlimitation: quaternary ammonium salts e.g., chloride, bromides, iodides,dimethylsulfates, diethylsulfates, nitrites, hydroxides, alkoxides, orthe like, or mixtures or combinations thereof; salts of nitrogen bases;or mixtures or combinations thereof. Exemplary quaternary ammonium saltsinclude, without limitation, quaternary ammonium salts from an amine anda quaternarization agent, e.g., alkylchlorides, alkylbromide, alkyliodides, alkyl sulfates such as dimethyl sulfate, diethyl sulfate, etc.,dihalogenated alkanes such as dichloroethane, dichloropropane,dichloroethyl ether, epichlorohydrin adducts of alcohols, ethoxylates,or the like; or mixtures or combinations thereof and an amine agent,e.g., alkylpyridines, especially, highly alkylated alkylpyridines, alkylquinolines, C6 to C24 synthetic tertiary amines, amines derived fromnatural products such as coconuts, or the like, dialkylsubstitutedmethyl amines, amines derived from the reaction of fatty acids or oilsand polyamines, amidoimidazolines of DETA and fatty acids, imidazolinesof ethylenediamine, imidazolines of diaminocyclohexane, imidazolines ofaminoethylethylenediamine, pyrimidine of propane diamine and alkylatedpropene diamine, oxyalkylated mono and polyamines sufficient to convertall labile hydrogen atoms in the amines to oxygen containing groups, orthe like or mixtures or combinations thereof. Exemplary examples ofsalts of nitrogen bases, include, without limitation, salts of nitrogenbases derived from a salt, e.g.: C1 to C8 monocarboxylic acids such asformic acid, acetic acid, propanoic acid, butanoic acid, pentanoic acid,hexanoic acid, heptanoic acid, octanoic acid, 2-ethylhexanoic acid, orthe like; C2 to C12 dicarboxylic acids, C2 to C12 unsaturated carboxylicacids and anhydrides, or the like; polyacids such as diglycolic acid,aspartic acid, citric acid, or the like; hydroxy acids such as lacticacid, itaconic acid, or the like; aryl and hydroxy aryl acids; naturallyor synthetic amino acids; thioacids such as thioglycolic acid (TGA);free acid forms of phosphoric acid derivatives of glycol, ethoxylates,ethoxylated amine, or the like, and aminosulfonic acids; or mixtures orcombinations thereof and an amine, e.g.: high molecular weight fattyacid amines such as cocoamine, tallow amines, or the like; oxyalkylatedfatty acid amines; high molecular weight fatty acid polyamines (di, tri,tetra, or higher); oxyalkylated fatty acid polyamines; amino amides suchas reaction products of carboxylic acid with polyamines where theequivalents of carboxylic acid is less than the equivalents of reactiveamines and oxyalkylated derivatives thereof; fatty acid pyrimidines;monoimidazolines of EDA, DETA or higher ethylene amines, hexamethylenediamine (HMDA), tetramethylenediamine (TMDA), and higher analogsthereof; bisimidazolines, imidazolines of mono and polyorganic acids;oxazolines derived from monoethanol amine and fatty acids or oils, fattyacid ether amines, mono and bis amides of aminoethylpiperazine; GAA andTGA salts of the reaction products of crude tall oil or distilled talloil with diethylene triamine; GAA and TGA salts of reaction products ofdimer acids with mixtures of poly amines such as TMDA, HMDA and1,2-diaminocyclohexane; TGA salt of imidazoline derived from DETA withtall oil fatty acids or soy bean oil, canola oil, or the like; ormixtures or combinations thereof.

Other Additives

The drilling fluids of this invention can also include other additivesas well such as scale inhibitors, carbon dioxide control additives,paraffin control additives, oxygen control additives, or otheradditives.

Scale Control

Suitable additives for Scale Control and useful in the compositions ofthis invention include, without limitation: Chelating agents, e.g., Na,K or NH₄ ⁺ salts of EDTA; Na, K or NH₄ ⁺ salts of NTA; Na, K or NH₄ ⁺salts of Erythorbic acid; Na, K or NH₄ ⁺ salts of thioglycolic acid(TGA); Na, K or NH₄ ⁺ salts of Hydroxy acetic acid; Na, K or NH₄ ⁺ saltsof Citric acid; Na, K or NH₄ ⁺ salts of Tartaric acid or other similarsalts or mixtures or combinations thereof. Suitable additives that workon threshold effects, sequestrants, include, without limitation:Phosphates, e.g., sodium hexametaphosphate, linear phosphate salts,salts of polyphosphoric acid, Phosphonates, e.g., nonionic such as HEDP(hydroxythylidene diphosphoric acid), PBTC (phosphoisobutane,tricarboxylic acid), Amino phosphonates of: MEA (monoethanolamine), NH₃,EDA (ethylene diamine), Bishydroxyethylene diamine, Bisaminoethylether,DETA (diethylenetriamine), HMDA (hexamethylene diamine), Hyperhomologues and isomers of HMDA, Polyamines of EDA and DETA,Diglycolamine and homologues, or similar polyamines or mixtures orcombinations thereof; Phosphate esters, e.g., polyphosphoric acid estersor phosphorus pentoxide (P₂O₅) esters of: alkanol amines such as MEA,DEA, triethanol amine (TEA), Bishydroxyethylethylene diamine;ethoxylated alcohols, glycerin, Tris & Tetra hydroxy amines; ethoxylatedalkyl phenols (limited use due to toxicity problems), Ethoxylated aminessuch as monoamines such as MDEA and higher amines from 2 to 24 carbonsatoms, diamines 2 to 24 carbons carbon atoms, or the like; Polymers,e.g., homopolymers of aspartic acid, soluble homopolymers of acrylicacid, copolymers of acrylic acid and methacrylic acid, terpolymers ofacylates, AMPS, etc., hydrolyzed polyacrylamides, poly malic anhydride(PMA); or the like; or mixtures or combinations thereof.

Carbon Dioxide Neutralization

Suitable additives for CO₂ neutralization and for use in thecompositions of this invention include, without limitation, MEA, DEA,isopropylamine, cyclohexylamine, morpholine, diamines,dimethylaminopropylamine (DMAPA), ethylene diamine, methoxy proplyamine(MOPA), dimethylethanol amine, methyldiethanolamine (MDEA) & oligomers,imidazolines of EDA and homologues and higher adducts, imidazolines ofaminoethylethanolamine (AEEA), aminoethylpiperazine, aminoethylethanolamine, di-isopropanol amine, DOW AMP-90™, Angus AMP-95, dialkylamines(of methyl, ethyl, isopropyl), mono alkylamines (methyl, ethyl,isopropyl), trialkyl amines (methyl, ethyl, isopropyl),bishydroxyethylethylene diamine (THEED), or the like or mixtures orcombinations thereof.

Paraffin Control

Suitable additives for Paraffin Removal, Dispersion, and/or paraffinCrystal Distribution include, without limitation: Cellosolves availablefrom DOW Chemicals Company; Cellosolve acetates; Ketones; Acetate andFormate salts and esters; surfactants composed of ethoxylated orpropoxylated alcohols, alkyl phenols, and/or amines; methylesters suchas coconate, laurate, soyate or other naturally occurring methylestersof fatty acids; sulfonated methylesters such as sulfonated coconate,sulfonated laurate, sulfonated soyate or other sulfonated naturallyoccurring methylesters of fatty acids; low molecular weight quaternaryammonium chlorides of coconut oils soy oils or C10 to C24 amines ormonohalogenated alkyl and aryl chlorides; quanternary ammonium saltscomposed of disubstituted (e.g., dicoco, etc.) and lower molecularweight halogenated alkyl and/or aryl chlorides; gemini quaternary saltsof dialkyl (methyl, ethyl, propyl, mixed, etc.) tertiary amines anddihalogenated ethanes, propanes, etc. or dihalogenated ethers such asdichloroethyl ether (DCEE), or the like; gemini quaternary salts ofalkyl amines or amidopropyl amines, such as cocoamidopropyldimethyl, bisquaternary ammonium salts of DCEE; or mixtures or combinations thereof.Suitable alcohols used in preparation of the surfactants include,without limitation, linear or branched alcohols, specially mixtures ofalcohols reacted with ethylene oxide, propylene oxide or higheralkyleneoxide, where the resulting surfactants have a range of HLBs.Suitable alkylphenols used in preparation of the surfactants include,without limitation, nonylphenol, decylphenol, dodecylphenol or otheralkylphenols where the alkyl group has between about 4 and about 30carbon atoms. Suitable amines used in preparation of the surfactantsinclude, without limitation, ethylene diamine (EDA), diethylenetriamine(DETA), or other polyamines. Exemplary examples include Quadrols,Tetrols, Pentrols available from BASF. Suitable alkanolamines include,without limitation, monoethanolamine (MEA), diethanolamine (DEA),reactions products of MEA and/or DEA with coconut oils and acids and/orN-methyl-2-pyrrolidone is oil solubility is desired.

Oxygen Control

The introduction of water downhole often is accompanied by an increasein the oxygen content of downhole fluids due to oxygen dissolved in theintroduced water. Thus, the materials introduced downhole must work inoxygen environments or must work sufficiently well until the oxygencontent has been depleted by natural reactions. For system that cannottolerate oxygen, then oxygen must be removed or controlled in anymaterial introduced downhole. The problem is exacerbated during thewinter when the injected materials include winterizers such as water,alcohols, glycols, Cellosolves, formates, acetates, or the like andbecause oxygen solubility is higher to a range of about 14-15 ppm invery cold water. Oxygen can also increase corrosion and scaling. In CCT(capillary coiled tubing) applications using dilute solutions, theinjected solutions result in injecting an oxidizing environment (O₂)into a reducing environment (CO₂, H₂S, organic acids, etc.).

Options for controlling oxygen content includes: (1) de-aeration of thefluid prior to downhole injection, (2) addition of normal sulfides toproduct sulfur oxides, but such sulfur oxides can accelerate acid attackon metal surfaces, (3) addition of erythorbates, ascorbates,diethylhydroxyamine or other oxygen reactive compounds that are added tothe fluid prior to downhole injection; and (4) addition of corrosioninhibitors or metal passivation agents such as potassium (alkali) saltsof esters of glycols, polyhydric alcohol ethyloxylates or other similarcorrosion inhibitors. Exemplary examples oxygen and corrosion inhibitingagents include mixtures of tetramethylene diamines, hexamethylenediamines, 1,2-diaminecyclohexane, amine heads, or reaction products ofsuch amines with partial molar equivalents of aldehydes. Other oxygencontrol agents include salicylic and benzoic amides of polyamines, usedespecially in alkaline conditions, short chain acetylene diols orsimilar compounds, phosphate esters, borate glycerols, urea and thioureasalts of bisoxalidines or other compound that either absorb oxygen,react with oxygen or otherwise reduce or eliminate oxygen.

Salt Inhibitors

Suitable salt inhibitors for use in the fluids of this inventioninclude, without limitation, Na Minus-Nitrilotriacetamide available fromClearwater International, LLC of Houston, Tex.

Advantages of the Anti-Swelling Additives of this Invention

The present invention differs from the compositions and methods of U.S.Pat. No. 5,635,458 in that this patent teaches the use of cholinechloride in a convention drilling fluid. Unlike under-balanced drillingfluids, convention drilling fluid or so-called over-balanced drillingfluids drill through a reservoir at hydrostatic pressures higher thanthe hydrostatic pressures of the formation and require filtrationcontrol agents and viscosifiers. These two components in conjunctionwith a weighing agent are required to establish an impermeablefilter-cake on face of the formation preventing losses of the drillingfluid to the formation. In under-balanced drilling, these components arenot required since the hydrostatic formation pressure is higher than thehydrostatic pressure of the drilling fluid because no filter-cake needbe established and no or very little of the drilling fluid penetratesthe formation.

The present invention differs from the compositions and methods of U.S.Pat. No. 5,908,814, as is in U.S. Pat. No. 5,635,458, where it teachesthe use of choline chloride in conventional over-balanced drillingfluid. U.S. Pat. No. 6,247,543 also teaches the use of choline chloridein conventional over-balanced drilling fluid.

Conventional Drilling Fluids with the Choline Carboxylates of thisInvention

It is essential that the drilling fluid ultimately selected andformulated for use in any particular well application be appropriate forthe conditions of the well. Therefore, although the base ingredientsremain the same, i.e., salt or fresh water and the drilling fluidadditives of this invention, other components can be added.

Specifically, materials generically referred to as gelling materials,thinners, fluid loss control agents, and weight materials are typicallyadded to water base drilling fluid formulations. Of these additionalmaterials, each can be added to the formulation in a concentration asrheologically and functionally required by drilling conditions. Typicalgelling materials used in aqueous based drilling fluids are bentonite,sepiolite, and attapulgite clays and anionic high-molecular weight,water-soluble polymers such as partially hydrolyzed polyacrylamides.

An important aspect of the present invention is the presence of a weightmaterial in the drilling fluid. Materials that have demonstrated utilityas weight materials include Galena (PbS), Hematite (Fe₂O₃), Magnetite(Fe₃O₄), iron oxide (Fe₂O₃) (manufactured), Illmenite (FeO.TiO₂), Barite(BaSO₄), Siderite (FeCO₃), Celestite (SrSO₄), Dolomite (CaCO₃MgCO₃), andCalcite (CaCO₃). The weight material is added to the drilling fluid in afunctionally effective amount largely dependent on the nature of theformation being drilled. Weight materials are typically present only indrilling fluids and are not generally found in well treatment andstimulation fluids such as fracturing fluids. In fracturing fluids theuse of weight materials is specifically avoided for functional reasons.

Similarly, it has been found beneficial to add lignosulfonates asthinners for water-base drilling fluids. Typically lignosulfonates,modified lignosulfonates, polyphosphates and tannins are added. In otherembodiments, low molecular weight polyacrylates can also be added asthinners. Thinners are added to a drilling fluid to reduce flowresistance and control gelation tendencies. Other functions performed bythinners include reducing filtration and cake thickness, counteractingthe effects of salts, minimizing the effects of water on the formationsdrilled, emulsifying oil in water, and stabilizing mud properties atelevated temperatures.

As mentioned previously, the drilling fluid composition of thisinvention contains a weight material. The quantity depends upon thedesired density of the final composition. The most preferred weightmaterials include, but are not limited to, barite, hematite calciumcarbonate, magnesium carbonate and the like.

Finally, anionic fluid loss control agents such as modified lignite,polymers, modified starches and modified celluloses can be added to thewater base drilling fluid system of this invention.

As indicated, the additives of the invention are selected to have lowtoxicity and to be compatible with common anionic drilling fluidadditives such as polyanionic carboxymethylcellulose (PAC or CMC),polyacrylates, partially-hydrolyzed polyacrylamides (PHPA),lignosulfonates, xanthan gum, etc.

Several preferred embodiments of the invention were prepared for use inthe following examples. The several samples of condensates were preparedusing various catalysts, as noted.

Triethanolaminemethyl chloride was prepared by mixing 60 grams oftriethanolamine with 20 grams of distilled water. 20 grams of methylchloride was then added to the solution. The solution was heated atabout 65° C. for approximately 6 hours. Upon completion of the reactionthe excess methyl chloride was evaporated.

In an alternative embodiment, an improved drilling fluid additive wasformed by reacting triethanolamine withN,N,N-trimethyl-2-hydroxy-3-chloropropane ammonium chloride to form awater soluble diquat. The reaction was conducted generally according tothe procedure set forth above for the preparation of thetriethanolaminemethyl chloride.

Condensates of triethanolamine were prepared using various catalysts,followed by quaternization of the condensates. In general, thecondensate samples were prepared by mixing 200 grams of triethanolaminewith 1 to 10% of the catalyst by weight. The catalysts employed inpreparing the samples were sodium hydroxide, zinc chloride and calciumchloride.

Generally, the mixtures were heated between about 100° C. to about 250°C. for several hours until the desired condensation was achieved. Thecondensation water was distilled off during the reaction. Thetriethanolamine condensates were then quaternized according to theprocedure set forth for the preparation of the triethanolaminemethylchloride described above.

The simple glycols are useful for lowering water activity and freezingpoint of an aqueous solution. At moderate concentrations, they can lowerthe water activity to a level equal to or less than that of most gumboshales commonly encountered in offshore drilling. This lowering of wateractivity aids in preventing water adsorption through osmotic effects.The lowering of the freezing point can be utilized to prevent theformation of gas hydrates in deep water drilling while eliminating theuse of large amounts of salts.

The water-based drilling fluid system of this invention comprises awater-miscible glycol with a molecular weight of less than about 200,such as ethylene glycol, diethylene glycol, triethylene glycol,propylene glycol, butylene glycol and mixtures thereof, in a range from30% to 70% by weight, preferably 30% to 50% by weight of the aqueousphase of the said drilling fluid. Incorporated in the aqueous phase ofthe drilling fluid is an organic cationic material selected from thegroup consisting of choline hydroxide, choline chloride, cholinecarbonate, choline bicarbonate, choline sulfate and mixtures thereof, oran organic potassium salt such as potassium acetate or potassiumformate, preferably choline chloride, in a range from 3% by weight up tosaturation, preferably 5% to 20% by weight of the aqueous phase.

A filtration control agent may be added to control the fluid loss of thedrilling fluid. Suitable filtration control agents are well known in theart and may include but are not limited to polyanionic cellulose,polyacrylate, polysaccharide, lignite, lignosulfonate, and mixturesthereof.

A viscosifier, such as biopolymers, clays and mixtures thereof, also maybe added to increase viscosity and suspend solids and weightingmaterials.

The density of the drilling fluids can be adjusted by using barite,hematite, calcium carbonate, and mixtures thereof.

To minimize solubilization problems of polymer additives that may beencountered at high concentrations of glycol, the filtration controlagent and viscosifier should be pre-solubilized in water before theaddition of glycol.

The present invention is directed to a water-base drilling fluid for usein drilling wells through a formation containing a shale which swells inthe presence of water. Generally the drilling fluid of the presentinvention includes a weight material, a shale hydration inhibition agentand an aqueous continuous phase. As disclosed below, the drilling fluidsof the present invention may also include additional components, such asfluid loss control agents, bridging agents, lubricants, anti-bit ballingagents, corrosion inhibition agents, surfactants and suspending agentsand the like which may be added to an aqueous based drilling fluid.

The shale hydration inhibition agent of the present invention ispreferably a polyoxyalkyleneamine which inhibits the swelling of shalethat may be encountered during the drilling process. Preferably thealkylene group is a propylene, thus the shale inhibition agents of thepresent invention may be selected from the general group ofpolyoxypropyleneamines. While a variety of members of this group mayserve as shale inhibition agents, we have found that compounds havingthe general formulaH₂N—CH(CH₃)CH₂{—OCH₂CH(CH₃)—}_(x)—NH₂provide effective inhibition of shale hydration.

The value of x has been found to be a factor in the ability of the shalehydration inhibitors to carry out their desired role. The value of x maybe a whole number or fractional number that reflects the averagemolecular weight of the compound. In one embodiment of the presentinvention x may have a value less than 15 and preferably have a valuebetween about 1 and about 5. In one particularly preferred embodiment,the value of x has an average number of about 2.6.

Alternatively and in another embodiment of the present invention, thevalue of x is determined by the molecular weight of the shale hydrationinhibition agent. Thus x is selected such that the average molecularweight of the hydration inhibition agent is from about 132 to about 944and preferably x is selected such that the average molecular weight ofthe hydration inhibition agent is from about 190 to about 248. However,regardless of how a particular value of x is selected, the key criteriaare that the shale hydration inhibition agent should function asintended in the drilling fluid and should minimize any impact it mighthave on the other properties of the drilling fluid.

The shale hydration inhibition agent should be present in sufficientconcentration to reduce either or both the surface hydration basedswelling and/or the osmotic based swelling of the shale. The exactamount of the shale hydration inhibition agent present in a particulardrilling fluid formulation can be determined by a trial and error methodof testing the combination of drilling fluid and shale formationencountered. Generally however, the shale hydration inhibition agent ofthe present invention may be used in drilling fluids in a concentrationfrom about 1 to about 18 pounds per barrel (lbs/bbl or ppb) and morepreferably in a concentration from about 2 to about 12 pounds per barrelof drilling fluid.

In addition to the inhibition of shale hydration by the shale hydrationinhibition agent, other properties are beneficially achieved. Inparticular it has been found that the shale hydration inhibition agentsof the present invention may also be further characterized by theircompatibility with other drilling fluid components, tolerant tocontaminants, temperature stability and low toxicity. These factorscontribute to the concept that the shale hydration inhibition agents ofthe present invention may have broad application both in land baseddrilling operations as well as offshore drilling operations.

The drilling fluids of the present invention include a weight materialin order to increase the density of the fluid. The primary purpose forsuch weighting materials is to increase the density of the drillingfluid so as to prevent kick-backs and blow-outs. One of skill in the artshould know and understand that the prevention of kick-backs andblow-outs is important to the safe day to day operations of a drillingrig. Thus the weight material is added to the drilling fluid in afunctionally effective amount largely dependent on the nature of theformation being drilled.

Weight materials suitable for use in the formulation of the drillingfluids of the present invention may be generally selected from any typeof weighting materials be it in solid, particulate form, suspended insolution, dissolved in the aqueous phase as part of the preparationprocess or added afterward during drilling. It is preferred that theweight material be selected from the group including barite, hematite,iron oxide, calcium carbonate, magnesium carbonate, organic andinorganic salts, and mixtures and combinations of these compounds andsimilar such weight materials that may be utilized in the formulation ofdrilling fluids.

The aqueous based continuous phase may generally be any water basedfluid phase that is compatible with the formulation of a drilling fluidand is compatible with the shale hydration inhibition agents disclosedherein. In one preferred embodiment, the aqueous based continuous phaseis selected from: fresh water, sea water, brine, mixtures of water andwater soluble organic compounds and mixtures thereof. The amount of theaqueous based continuous phase should be sufficient to form a waterbased drilling fluid. This amount may range from nearly 100% of thedrilling fluid to less than 30% of the drilling fluid by volume.Preferably, the aqueous based continuous phase is from about 95 to about30% by volume and preferably from about 90 to about 40% by volume of thedrilling fluid.

In addition to the other components previously noted, materialsgenerically referred to as gelling materials, thinners, and fluid losscontrol agents, are optionally added to water base drilling fluidformulations. Of these additional materials, each can be added to theformulation in a concentration as Theologically and functionallyrequired by drilling conditions. Typical gelling materials used inaqueous based drilling fluids are bentonite, sepiolite clay, attapulgiteclay, anionic high-molecular weight polymer and biopolymers.

Thinners such as lignosulfonates are also often added to water-basedrilling fluids. Typically lignosulfonates, modified lignosulfonates,polyphosphates and tannins are added. In other embodiments, lowmolecular weight polyacrylates can also be added as thinners Thinnersare added to a drilling fluid to reduce flow resistance and controlgelation tendencies. Other functions performed by thinners includereducing filtration and filter cake thickness, counteracting the effectsof salts, minimizing the effects of water on the formations drilled,emulsifying oil in water, and stabilizing mud properties at elevatedtemperatures.

A variety of fluid loss control agents may be added to the drillingfluids of the present invention that are generally selected from a groupconsisting of synthetic organic polymers, biopolymers, and mixturesthereof. The fluid loss control agents such as modified lignite,polymers, modified starches and modified celluloses may also be added tothe water base drilling fluid system of this invention. In oneembodiment it is preferred that the additives of the invention should beselected to have low toxicity and to be compatible with common anionicdrilling fluid additives such as polyanionic carboxymethylcellulose (PACor CMC), polyacrylates, partially-hydrolyzed polyacrylamides (PHPA),lignosulfonates, xanthan gum, mixtures of these and the like.

The drilling fluid of the present invention may further contain anencapsulating agent generally selected from the group consisting ofsynthetic organic, inorganic and bio-polymers and mixtures thereof. Therole of the encapsulating agent is to absorb at multiple points alongthe chain onto the clay particles, thus binding the particles togetherand encapsulating the cuttings. These encapsulating agents help improvethe removal of cuttings with less dispersion of the cuttings into thedrilling fluids. The encapsulating agents may be anionic, cationic ornon-ionic in nature.

Other additives that could be present in the drilling fluids of thepresent invention include products such as lubricants, penetration rateenhancers, defoamers, corrosion inhibitors and loss circulationproducts. Such compounds should be known to one of ordinary skill in theart of formulating aqueous based drilling fluids.

The use of the above disclosed drilling fluids is contemplated as beingwithin the scope of the present invention. Such use would beconventional to the art of drilling subterranean wells and one havingskill in the art should appreciate such processes and applications.

EXPERIMENTS OF THE INVENTION Example 1

This examples illustrates a composition of this invention including 0.5wt. % of C-100 and 0.5 wt. % of AI-600 in deionized water. C-100 is acorrosion inhibitor available from Clearwater Engineered Chemistry, aWeatherford International, Houston, Tex. and includes a scale controlagent comprising a triethanolamine polyphosphoric acid ester, a firstcorrosion inhibitor comprising an amine salt (morpholine residues)reaction product of boric acid and urea, a mixture ammoniumsulfite-bisulfate, a second corrosion inhibitor comprisingcocoamidopropyldimethylamine, a tertiary amine of coconut oil anddimethylaminopropyl amine (DMAPA) and isopropanol. AI-600 is a hightemperature corrosion inhibitor also available from ClearwaterEngineered Chemistry, a Weatherford International, Houston, Tex. andincludes a quinoline quaternary surfactant, a blend of acetylenicalcohol replacement solvents and a highly effective dispersant.

The composition was prepared by adding 0.5 wt. % of C-100 to sufficientdeionized water with stirring to produce the desired formulation. Afterthe addition of C-100, 0.5 wt. % of AI-600 was added with stirring.

Example 2

This examples illustrates a composition of this invention including 0.5wt. % of C-119 and 0.5 wt. % of AI-600 in deionized water. C-119 is acorrosion inhibitor available from Clearwater Engineered Chemistry, aWeatherford International, Houston, Tex. and includes a scale controlagent comprising a triethanolamine polyphosphoric acid ester, a firstcorrosion inhibitor comprising an amine salt (morpholine residues)reaction product of boric acid and urea, a mixture ammoniumsulfite-bisulfate, a second corrosion inhibitor comprisingcocoamidopropyldimethylamine, a tertiary amine of coconut oil, AkzoArmeen DM12D a lauryldimethyl amine and isopropanol.

The composition was prepared by adding 0.5 wt. % of C-119 to sufficientdeionized water with stirring to produce the desired formulation. Afterthe addition of C-119, 0.5 wt. % of AI-600 was added with stirring.

Example 3

This examples illustrates a composition of this invention including 0.5wt. % of C-100, 0.5 wt. % CorrFoam 1 and 0.5 wt. % of AI-600 indeionized water. CorrFoam 1 is an oxygen inhibitor available fromClearwater Engineered Chemistry, a Weatherford International, Houston,Tex. and includes the potassium salt of 100% active polyphosphoric acidester of ethylene glycol.

The composition was prepared by adding 0.5 wt. % of C-100 to sufficientdeionized water with stirring to produce the desired formulation. Afterthe addition of C-100, 0.5 wt. % of CorrFoam 1 was added with stirring.Finally, 0.5 wt. % of AI-600 was added with stirring.

Example 4

This examples illustrates a composition of this invention including 0.5wt. % of C-119, 0.5 wt. % CorrFoam 1 and 0.5 wt. % of AI-600 indeionized water.

The composition was prepared by adding 0.5 wt. % of C-119 to sufficientdeionized water with stirring to produce the desired formulation. Afterthe addition of C-119, 0.5 wt. % of CorrFoam 1 was added with stirring.Finally, 0.5 wt. % of AI-600 was added with stirring.

Example 5

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 0.5 wt. % Corrfoam 1 and0.5 wt. % AI-600 in deionized water.

The composition was prepared by adding 0.5 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 0.5 wt. % of AI-600 wasadded with stirring.

Example 6

After testing of the composition of Example 3, 1.0 wt. % CorrFoam 1, 1.0wt. % C-100 and 1.0 wt. % of AI-600 were added with stirring.

Example 7

After testing of the composition of Example 4, 1.0 wt. % CorrFoam 1, 1.0wt. % C-119 and 1.0 wt. % of AI-600 were added with stirring.

Example 8

After testing of the composition of Example 5, 1.0 wt. % CorrFoam 1 and1.0 wt. % AI-600 were added with stirring.

Example 9

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 0.5 wt. % Corrfoam 1, 0.5wt. % AI-600 and 1.0 wt. % Alpha One in deionized water. Alpha One is asulfur scavenger available from Clearwater Engineered Chemistry, aWeatherford International, Houston, Tex. and is a reaction product offormaldehyde and a formaldehyde-monoethanolamine condensate.

The composition was prepared by adding 0.5 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 0.5 wt. % of AI-600 wasadded with stirring. Finally, 1.0 wt. % of Alpha One was added withstirring.

Example 10

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 0.5 wt. % Corrfoam 1, 0.5wt. % AI-600 and 1.0 wt. % Sufla Clear® 8849 in deionized water. SuflaClear® 8849 is an oil soluble sulfur scavenger available from ClearwaterEngineered Chemistry, a Weatherford International, Houston, Tex. and isa reaction product between paraformylaldehyde and di-n-butylamine madewith a large excess of di-n-butylamine.

The composition was prepared by adding 0.5 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 0.5 wt. % of AI-600 wasadded with stirring. Finally, 1.0 wt. % of Sufla Clear® 8849 was addedwith stirring.

Example 11

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 0.5 wt. % Corrfoam 1, 0.5wt. % AI-600 and 1.0 wt. % Sufla Clear® 8199 in deionized water. SuflaClear® 8199 is an oil soluble sulfur scavenger available from ClearwaterEngineered Chemistry, a Weatherford International, Houston, Tex. and isa reaction product between formylaldehyde and dimethylamino propylamine,which forms a triazine.

The composition was prepared by adding 0.5 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 0.5 wt. % of AI-600 wasadded with stirring. Finally, 1.0 wt. % of Sufla Clear® 8199 was addedwith stirring.

Example 12

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 0.5 wt. % Corrfoam 1, 0.5wt. % AI-600 and 0.5 wt. % A-2802 N in deionized water. A-2802 N is thesodium salt of AMP (aminomethylenetriphosphonic acid).

The composition was prepared by adding 0.5 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 0.5 wt. % of AI-600 wasadded with stirring. Finally, 0.5 wt. % of A-2802 was added withstirring.

Example 13

This examples illustrates a composition of this invention including 1.0wt. % CorrFoam 1, 1.0 wt. % of C-100 and 1.0 wt. % of AI-600 indeionized water.

The composition was prepared by adding 1.0 wt. % of C-100 to sufficientdeionized water with stirring to produce the desired formulation. Afterthe addition of C-100, 1.0 wt. % of CorrFoam 1 was added with stirring.Finally 1.0 wt. % of AI-600 was added with stirring.

Example 14

This examples illustrates a composition of this invention including 1.0wt. % CorrFoam 1, 1.0 wt. % of C-119 and 1.0 wt. % of AI-600 indeionized water.

The composition was prepared by adding 1.0 wt. % of C-119 to sufficientdeionized water with stirring to produce the desired formulation. Afterthe addition of C-119, 1.0 wt. % of CorrFoam 1 was added with stirring.Finally 1.0 wt. % of AI-600 was added with stirring.

Example 15

This examples illustrates a composition of this invention including 1.0wt. % CorrFoam 1 and 1.0 wt. % of AI-600 in deionized water.

The composition was prepared by adding 0.5 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation, followed by the addition of 1.0 wt. % of AI-600 withstirring.

Example 16

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 1.0 wt. % Corrfoam 1, 1.0wt. % AI-600 and 2.0 wt. % Alpha One in deionized water.

The composition was prepared by adding 1.0 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 1.0 wt. % of AI-600 wasadded with stirring. Finally, 2.0 wt. % of Alpha One was added withstirring.

Example 17

This examples illustrates a composition of this invention including aphosphate ester, a cationic surfactant and a 1.0 wt. % Corrfoam 1, 1.0wt. % AI-600 and 2.0 wt. % 8849 in deionized water.

The composition was prepared by adding 1.0 wt. % of CorrFoam 1 tosufficient deionized water with stirring to produce the desiredformulation. After the addition of CorrFoam 1, 1.0 wt. % of AI-600 wasadded with stirring. Finally, 2.0 wt. % of 8849 was added with stirring.

Corrosion Testing

Tests 1-6

The pH values of the solutions were originally about pH 8, but wereadjust to about pH 10 by the addition of a sodium hydroxide solution.The above test solutions were placed in a testing vessel and aelectrodes were placed in the solutions and maintained with stirring ata temperature of about 120° F. The results of these tests are tabulatedin Table IA and shown graphically in FIGS. 1A&B. Looking at FIG. 1C, anelectrode is shown that is exposed to anon-corrosive environment and oneexposed to a corrosive environment. Looking at FIG. 1D, photos of thesolutions are shown after the addition of sodium sulfide and CO₂, whichproduces H₂S in situ.

TABLE IA Corrosion Test Example 1 Example 2 Example 3 Example 4 Example5 Blank Test 1 Test 2 Test 3 Test 4 Test 5 Test 6 Im- Im- Im- Im- Im-Im- Time Rate balance Rate balance Rate balance Rate balance Ratebalance Rate balance Comments  0:00:00 0 0 0 0 0 0 0 0 0 0 0 0  0:30:009.63 5.52 8.27 16.31 8.14 10.19 7.23 12.89 8.98 16.6 62.22 73.41 1:00:00 8.8 3.15 7.66 3.54 10.8 0.95 9.84 5.61 11.36 8.05 60.69 44.49 1:30:00 7.61 2.71 6.3 3.86 8.95 0.31 7.57 5.4 12.83 9.52 57.81 23.81 2:00:00 7.26 2.54 10.08 6.32 17.58 0.06 6.59 5.77 13.63 9.74 55.21 2.33 2:30:00 34.53 0.07 29.82 10.75 18.6 1.56 17.3 17.35 14.25 9.53 52.219.13  3:00:00 41.52 34.66 33.7 24.36 48.87 0.07 15 16.78 14.42 9.2451.61 20.16  3:30:00 38.98 41.28 18.49 58.04 44.41 4.93 28.03 9.64 13.997.67 51.72 13.26  4:00:00 37.46 23.68 30.71 76.28 35.93 6.87 25.51 9.3113.54 7.03 44.94 40.02  4:30:00 36.56 22.41 30.38 64.27 33.62 4.92 23.8221.38 12.46 6.03 43.16 55.54  5:00:00 37.02 14.4 30.77 62.22 30.1 4.4523.32 24.3 11.45 5.05 40.16 71.4  5:30:00 37.31 9.98 30.61 55.91 29.854.49 20.78 26.38 10.79 4.27 37.6 67.04  6:00:00 39.91 8.66 31.03 50.9224.98 3.58 20.87 24.84 10.05 3.91 35.19 56.05  6:30:00 38.85 1.87 31.4243.57 27.16 1.93 19.14 23.82 9.53 3.22 31.95 41.06  7:00:00 39.99 0.3931.54 38.15 24.5 0.38 18.61 23.65 9.23 2.55 30.7 35.09  7:30:00 39.870.32 30.55 32.2 23.87 0.91 17.68 23 8.74 2.19 28.29 27.57  8:00:00 40.711.17 29.89 30.26 24.23 0.37 17.12 21.49 8.44 2.14 26.69 23.74  8:30:0040.36 3.09 30.64 27.55 21.47 0.14 16.46 21.32 8.11 1.64 25.54 21.06 9:00:00 40.85 6.82 29.01 21.18 18.42 0.19 15.75 21.38 7.66 1.57 24.1119.34  9:30:00 40.39 8.73 27.15 21.85 16.92 0.2 14.91 21.31 7.41 1.6123.49 18.22 10:00:00 39.48 9.11 27 15.83 17.24 0.05 14.59 21.18 7 1.2423.5 15.87 10:30:00 39.35 11.73 28.03 19.44 15.55 0.35 14.12 21.03 6.851.15 23.01 15.6 11:00:00 39.38 13.25 27.9 15.06 16.47 0.45 13.83 21.126.64 1.38 22.52 13.77 11:30:00 39.13 12.53 26.04 15.83 14.4 0.15 13.0222.19 6.39 1.16 21.46 12.37 12:00:00 38.88 14.35 26.69 14.01 13.47 0.8413.06 21.48 6.03 0.94 20.96 10.34 12:30:00 38.26 14.93 27.01 15.13 13.581.13 12.8 21.54 6.02 0.98 21.01 8.08 13:00:00 38.06 14.69 27.33 12.4712.29 1.31 12.59 22 5.85 0.81 20.95 4.87 13:30:00 38.94 13.78 25.3912.09 11.48 1.49 12.33 21.12 5.73 0.83 18.8 2.55 14:00:00 36.89 12.3724.87 8.87 11.06 1.72 12.24 21.6 5.36 0.99 19.19 0.14 14:30:00 38.3411.17 26.14 9.58 10.46 1.97 12.12 21.72 5.42 0.71 19.97 1.67 15:00:0037.46 12 28.47 7.21 10.39 2.11 12.09 21.32 5.44 0.8 18.5 2.97 15:30:0038.21 13.19 26.98 7.83 10.17 2.12 12.26 22.04 5.22 0.64 18.26 4.416:00:00 38.82 12.94 27.98 6.09 10 2.24 12.12 22.11 5.36 0.68 18.11 5.4416:30:00 39.47 12.74 28.22 5.98 9.66 2.58 12.21 21.84 5.09 0.71 17.45.64 17:00:00 38.4 13.16 27.62 4.5 9.39 2.44 12.12 21.78 5.14 0.65 17.35.36 Heat to 120° F., Add CO₂ 17:30:00 42.85 14.98 28.74 5.63 12.4 2.6612.13 21.48 7.75 0.74 19.59 5.04 18:00:00 107.41 3.35 74.17 8.04 22.327.64 43.65 71.34 11.3 0.51 32.22 8.64 18:30:00 98.74 25.18 101.77 16.4221.04 9.86 41.57 54.89 11.3 0.51 38.27 24.98 19:00:00 91.49 21.95 90.2441.29 19.38 12.08 36.15 28.82 11.3 0.51 38.27 24.98 19:30:00 82.25 26.2486.78 46.78 17.97 13.16 34.42 18.45 2.48 3.72 24.87 34.05 20:00:00100.16 32.93 86.71 57.51 17.28 13.88 30.77 11.01 2.48 3.72 24.87 34.0520:30:00 79.34 58.45 65.01 77.91 16.51 5.03 29.95 10.71 16.15 5.2 41.1641.97 21:00:00 66.73 15.29 49 18.88 16.68 1.46 26.94 20.29 20.93 8.3845.51 7.08 21:30:00 55.08 13.47 40.82 14.47 23.71 2.65 23.76 13.43 15.36.96 68.32 30.08 22:00:00 46.97 13.82 40.23 10.47 29.01 2.56 23.25 0.8417.36 8.46 94.97 34.58 22:30:00 43.5 14.96 47.32 4.6 58.97 3.23 28.80.79 21.31 8.34 107.32 31.11 23:00:00 51.7 13.63 49.03 2.43 61.76 1.7731.55 5.78 26.56 8.6 118.04 25.9 23:30:00 50.58 10.57 49.03 2.33 58.960.71 32.24 8.7 32.13 6.8 124.5 18.37 24:00:00 41.8 10.76 48.27 1.7955.31 0.12 32.87 14.09 34.47 5.82 124.24 9.21 24:30:00 37.78 9.26 46.271.36 55.5 0.58 33.65 16.94 37.96 4.1 124.54 4.66 25:00:00 36.55 7.7643.61 3.04 63.88 6.48 34.34 19.19 41.71 3.51 123.9 1.42 25:30:00 25.526.63 39.05 1.44 58.78 10.39 32.21 19.25 44.22 2.92 121.73 2.14 Hold @120° F., CO₂ off 26:00:00 23.05 5.8 35.31 2.41 56.3 11.43 31.52 20.4845.36 2.1 118.18 12.22 26:30:00 42.71 6.3 42.74 0.09 46.59 76.52 34.229.19 44.98 1.12 108.23 40.24 27:00:00 62.57 10.27 51.21 7.1 46.37 84.3632.99 41.98 40.03 6.17 100.88 54.82 27:30:00 67.37 18.07 59.33 9.93 50.871.92 30.37 38.75 40.63 10.11 94.13 69.4 28:00:00 65.29 35.54 66.3 5.6853.85 88.15 35.25 33.9 34.26 42.33 87.78 76.35 28:30:00 74.22 43.6460.45 1.16 49.32 100.32 31.44 33.15 32.37 33.35 82.47 74.32 29:00:0082.69 49.28 66.58 9.17 54.53 94.26 36.19 26.42 25.11 35.14 79.44 77.8729:30:00 91.15 61.25 70.28 25.15 54.15 95.12 35.65 23.39 22.58 35.5172.49 82.56 30:00:00 89.11 63.4 74.02 31.02 48.73 84.34 34.13 24.5118.07 27.73 68.76 81.17 30:30:00 99.37 75.16 77.69 47.7 47.88 80.3135.71 26.04 17.16 21.33 64.96 77.73 31:00:00 122.29 82.52 83.52 58.8645.1 71.66 35.33 27.83 15.89 19.48 62.94 71.32 31:30:00 126.01 98.6982.5 126.87 42.92 73.75 35.8 31.88 13.93 17.22 60.84 62.52 32:00:00118.45 118.7 84.34 136.67 41.98 65.81 35.3 34.93 13.01 12.11 58.55 58.5232:30:00 120.13 119.5 85.89 150.68 38.3 61.55 37.88 36.88 12.18 7.2757.19 37.1 33:00:00 131.8 115.81 86.74 152.84 36.66 60.39 36.78 39.189.43 5.76 55.85 25.07 33:30:00 141.95 98.34 86.18 163.57 35.16 55.635.54 41.12 8.62 4.39 57.1 11.48 34:00:00 143.33 41.38 87.55 172.4532.55 54.09 35.86 46.82 7.8 3.7 57.06 5.08 34:30:00 126.77 20.8 88.24182.87 32.36 50.19 38.54 43.81 7.18 3.36 60.44 2.27 35:00:00 116.69 9.8289.44 208.42 31.36 49.64 36.27 43.46 6.78 3.08 60.44 2.27 35:30:00118.74 37.01 91.45 218.25 29.25 44.27 34.01 46.17 6.47 3.07 66.51 4.7336:00:00 122.68 38.77 91.02 226.85 29.79 40.28 36.74 48.64 6.22 3.1380.31 16.6 36:30:00 150.08 26.98 91.58 226.7 29.01 42.67 34.64 44.536.22 3.13 90.51 32.96 37:00:00 121.92 17.78 91.34 225.47 26.26 36.7938.6 45.69 5.96 3.13 96.16 50.34 37:30:00 120.88 9.72 90.39 225.86 26.9239.52 37.62 41.49 5.72 3.1 94.89 44.57 38:00:00 116.75 8.35 90.46 229.3526.64 37.24 35.25 43.45 5.6 3.12 94.89 44.57 38:30:00 113.82 20.99 90.02232 24.39 32.55 34 41.91 5.6 3.12 93.16 28.82 39:00:00 126.2 30.59 89.35237 25.83 34.92 36.81 43.11 5.5 3.19 93.93 19.99 39:30:00 131.4 49.1989.74 239.61 25.69 35.93 36.21 41.42 5.45 3.35 92.21 15.19 40:00:00117.12 63.71 88.31 238.95 26.64 30.29 33.19 41.59 5.4 3.26 91.01 13.2540:30:00 132.88 69.95 87.8 237.8 25.38 30.16 36.54 40.36 5.37 3.48 89.6212.43 41:00:00 110.29 79.59 87.18 231.26 24.6 33.08 35.93 42.02 5.253.47 87.69 12.52 41:30:00 136.24 79.82 85.56 227.36 21.68 33.66 37.3739.45 9.01 3.49 84.41 13.87 Added 0.5% AI-600 42:00:00 133.84 87.4186.37 209.85 21.83 21.37 40.47 45.4 4.53 2.58 84.41 13.87 42:30:00 107.989.74 87.61 201.83 18.05 21.29 37.44 43.8 4.53 2.58 81.79 14.78 43:00:0096.69 83.82 86.94 196 18.68 16.83 35.11 45.12 3.98 2.16 76.31 13.19 AddCO₂ 43:30:00 97.89 65.66 86.95 188.81 17.76 20.66 36.09 45.38 3.4 1.977.16 9.61 44:00:00 107.31 68.94 94.23 176.17 24.68 22.54 31.63 42.537.41 1.33 110.71 16.97 44:30:00 63.34 106.97 67.97 17.44 22.61 13.128.18 34.27 10.89 2.52 96.23 50.54 45:00:00 41.94 14.94 44.14 7.55 20.129.96 23.65 30.22 14.06 2.06 98.31 43.9 Added 1 g Calcium Oxide 45:30:0014.5 8.16 29.11 8.49 34.48 9.11 21.51 30.78 27.96 1.1 74 14.61 46:00:0015.75 2.38 33.08 13.31 21.39 9.05 22.83 22.58 11.51 0.36 52.5 23.78Added CO₂ 46:30:00 9.59 3.78 14.81 6.46 12.21 1.19 22.12 21.57 8.72 0.8872.12 14.17 Added 1 g Sodium Sulfide 47:00:00 7.95 2.29 9.15 2.51 11.570.49 16.77 24.98 8.16 1.1 81.4 9.61 47:30:00 161.18 35.75 125.79 30.26291.51 1.61 16.77 24.98 8.16 1.1 187.96 117.94 48:00:00 31.9 34.73 83.8293.62 45.46 18.2 31.71 26.39 20.5 3.96 187.96 117.94

The solutions of Examples 6-8 were placed in a stainless steel bombalong with coupons 3-5 from the above test. The bombs were place in anoven on a roller mill and the temperature was adjusted to 450° F. Thebombs were rolled under their own pressure for one day and the couponsanalyzed pre-acid clean up and post acid clean up. The results aretabulated in Table IIA&B.

TABLE IIA Pre Acid Clean Up 450° F. Initial Final Time Density SACorrosion Corrosion Test # Coupon # Test Solution Weight Weight (Days)(g/cm³) (in²) (mpy) (lb/ft²/yr) Comments 3 3 Example 6 22.4590 22.4288 17.87 3.467 24.7 1.00 4 4 Example 7 22.1563 22.1540 1 7.87 3.467 1.9 0.085 5 Example 8 22.7284 22.7016 1 7.87 3.467 21.9 0.89 mpy = (weight lossin grams) * (22,300)/(Adt)

TABLE IIB Post Acid Clean Up 450° F. Test Initial Final Time Density SACorrosion Corrosion Test # Coupon # Solution Weight Weight (Days)(g/cm³) (in²) (mpy) (lb/ft²/yr) Comments 3 3 Example 6 22.4590 22.3918 17.87 3.467 54.9 2.23 No Pitting 4 4 Example 7 22.1563 22.1034 1 7.873.467 43.2 1.76 No Pitting 5 5 Example 8 22.7284 22.5719 1 7.87 3.467127.9 5.20 Small amt. of pitting mpy = (weight loss in grams) *(22,300)/(Adt)

The physical and chemical properties of the coupons that were used inthe above tests and in all subsequent tests are tabulated in Table IIC.

TABLE IIC Coupon Properties Physical Properties Tensile 73,670 PSI Yield60,00 PSI Elongation 41.50% Coupon Metallurgy Al 0.027 C 0.196 Ca 0.003Cr 0.034 Cu 0.015 Fe Balance Mn 0.609 Mo 0.012 Ni 0.007 P 0.011 S 0.003Si 0.091 V 0.002

Looking at FIGS. 2A-F, the coupons from Tests 3-5 are shown bothpre-acid wash, FIGS. 2A, C and E, and post acid wash, FIGS. 2B, D and F.

Test 7-12

The pH values of the solutions were originally about pH 8, but wereadjust to about pH 10 by the addition of a sodium hydroxide solution.The above test solutions were placed in a testing vessel and aelectrodes were placed in the solutions and maintained with stirring ata temperature of about 120° F. The results of these tests are tabulatedin Table IIIA and shown graphically in FIGS. 3A&B. Looking at FIG. 3C,the solutions used in Tests 7-12 are shown. Looking at FIG. 3D, theelectrodes that were placed in the solution of Test 7 and Test 8 areshown. Looking at FIG. 3E, the electrodes that were placed in thesolution of Test 9 and Test 10 are shown. Looking at FIG. 3F, theelectrodes that were placed in the solution of Test 11 and Test 12 areshown.

TABLE IIIA Corrosion Test Example 5 Example 9 Example 10 Example 11Example 12 Blank Test 7 Test 8 Test 9 Test 10 Test 11 Test 12 Im- Im-Im- Im- Im- Im- Time Rate balance Rate balance Rate balance Rate balanceRate balance Rate balance pH Comments 11:15  0 0 0 0 0 0 0 0 0 0 0 0Heat to 120° F. 11:45  33 27.55 28.4 48.81 12.67 3.63 18.74 49.87 26.0372.42 67.61 15.05 12:15  23.21 11.15 15.86 13.1 10.02 3.77 22 21.6323.96 1.41 58.23 36.12 12:45  18.98 3.17 15.41 4.19 11.28 3.17 18.289.58 25.89 4.18 51.5 23.29 1:15 15.31 0.37 14.19 5.56 14.03 1.83 16.379.68 28.84 6.31 46.37 16.76 1:45 13.16 3.04 14.13 6.56 13.72 0.03 16.379.68 30.93 5.33 41.41 10.11 2:15 10.78 4.2 14.13 6.56 11.64 0.97 14.956.8 30.4 4.07 36.94 7.61 2:45 10.78 4.2 15.26 6.51 11.64 0.97 14 4.728.8 6.13 33.26 5.17 3:15 10.18 3.58 14.6 4.54 9.43 0.29 14 4.7 24.844.13 32.19 4.11 3:45 9.39 3.26 13.1 3.03 9.43 0.29 13.55 3.59 20.49 1.1532.24 1.62 4:15 9.66 2.48 13.1 3.03 10.05 0.58 13.55 3.59 18.45 1.331.76 1.05 4:45 9.66 2.48 12.38 2.34 9.81 1.07 13.17 3.57 16.57 1.830.35 0.05 5:15 10.77 0.88 12.05 1.89 9.81 1.07 13.64 3.16 16.36 2.0129.57 2.44 5:45 10.74 0.45 12.12 2.22 8.63 1.74 13.64 3.16 16 2.18 29.933.69 6:15 10.85 0.34 12.14 2.58 9.21 1.47 13.04 2.51 15.79 2.78 29.465.16 6:45 11.05 0.99 12.15 2.94 9.21 1.47 12.99 1.88 15.88 2.48 29.595.75 7:15 11.11 2.38 12.16 2.68 8.72 2.05 12.99 1.88 15.62 2.63 35.96.41 7:45 10.96 3.51 12.06 2.42 8.37 2.47 13.33 1.92 15.62 2.46 29.96.61 8:15 11.16 3.82 12.09 2.36 9.02 1.52 13.42 1.64 16.34 2.51 36.827.69 8:45 10.9 4.35 12.03 2.35 9.02 1.52 13.3 1.62 16.3 3.51 30.3 8.219:15 10.92 4.54 11.87 2.38 8.57 0.34 13.09 2.24 16.22 3.67 30.24 6.949:45 10.83 5.07 11.87 2.32 8.94 0.45 13.25 2.21 15.66 3.72 31.13 6.9110:15  10.78 5.11 11.79 2.13 8.87 0.45 13.33 2.33 15.5 3.31 31.45 5.9910:45  10.9 4.69 11.76 1.61 8.59 0.01 13.33 2.33 15.6 2.83 32.38 6.511:15  11.01 4.82 11.74 1.47 8.59 0.3 13.1 1.77 16.02 2.68 32.94 6.2311:45  10.97 5.02 11.73 1.34 8.63 0.51 13.24 2.38 15.95 1.85 32.26 5.1412:15  10.87 5.69 11.71 1.16 8.74 0.17 13.6 1.58 17.41 2.09 42.3 4.7612:45  10.95 5.81 11.68 0.98 8.62 0.11 13.83 0.83 15.7 2.33 33.89 3.591:15 10.83 5.93 11.69 0.51 8.5 0.37 13.69 0.88 16.03 0.97 42.97 3.651:45 10.96 5.97 11.68 0.33 8.37 0.15 13.79 0.83 15.45 0.93 36.49 3.392:15 10.95 6.44 11.65 0.33 8.45 0.39 13.96 0.53 15.97 0.01 34.61 3.272:45 10.92 6.16 11.62 0.23 8.48 0.74 14.01 0 15.8 0.48 35.4 2.85 3:1510.98 6.2 11.65 0.25 8.42 1.34 14.45 0.46 15.63 0.79 36.13 3.02 3:4510.83 6.28 11.65 1.11 8.37 1.5 14.17 0.14 15.7 0.72 36.5 2.51 4:15 10.755.89 11.61 1.41 8.3 2.14 14.46 0.4 15.84 0.87 36.77 2.74 4:45 10.86 5.8511.53 1.67 8.25 2.19 14.4 0.27 15.64 0.55 46.73 3.75 5:15 10.86 6.1311.48 1.86 8.22 2.12 14.64 0.7 15.98 1.34 37.52 3.9 5:45 10.79 6.4211.49 2.07 8.16 2.02 14.51 0.97 15.68 1.34 48.2 5.57 6:15 10.82 6.7111.39 2.24 8.13 2 14.72 1.81 15.63 1.12 37.7 5.53 6:45 10.81 6.77 11.342.42 8.09 2.06 14.85 1.95 16.08 1.46 49.31 5.4 7:15 10.68 7.07 11.312.62 8.02 1.88 14.87 2.16 15.59 2.11 49.58 8.62 7:45 10.77 6.94 11.262.98 7.95 1.86 15.17 1.91 15.82 2.65 41.83 7.85 CO₂ turned on 8:15 26.656.65 11.65 3.18 9.54 1.53 15.64 1.75 28.35 1.32 48.72 10.7 6.44 8:45 8.85.72 28.39 12.15 23.19 0.52 25.05 7.06 54.14 44.29 83.72 40.14 6.35Added 1 gram white lime 9:15 8.57 3.28 12.46 8.4 34.69 3.58 43.3 18.7349.84 20.89 113.47 19.76 6.39 9:45 12.33 3.68 10.8 5.41 33.31 19.7846.68 42.22 61.54 26.55 140.97 31.12 6.16 10:15  10.21 3.61 7.66 1.8427.17 9.79 33.07 22.45 51.74 22.57 106.71 25.52 6.16 Added 5 mL hydratedwhite lime (2 grams total) 10:45  15.91 2.63 8.64 1.46 25.62 7.03 32.0619.87 54.68 30.1 124.57 20.36 6.42 11:15  19 4.59 9.57 1.38 25.74 5.427.7 16.14 48.25 24.9 109.28 11.93 6.34 Added 5 mL hydrated white lime(3 grams total) 11:45  9.06 8.14 6.05 3.38 30.06 2.29 29.7 20.64 45.0642.07 120.16 1.56 6.37 CO₂ turned off, Added 1 gram Sodium Sulfide12:15  11.44 15.56 3.68 1.36 11.25 6.26 20.82 21.71 18.77 35.39 247.2676.42 6.68 12:45  9.22 2.03 5.44 1.74 6.98 4.91 12.57 12.49 17.9 3.84141.74 53.26 6.74 1:15 9.22 2.03 6.8 1.43 5.82 1.63 9.76 11.5 18.3112.44 103.51 47.51 6.75 1:45 7.45 1.69 6.8 1.43 5.32 0.79 8.75 8.8920.89 15.37 73.05 10.66 6.77 2:15 9.55 2.32 6.98 0.51 5.27 0.47 8.58 6.920.17 10.91 62.27 11.76 6.81-6.39 CO₂ turned on 2:45 9.3 5.48 10.48 0.165.48 1.31 7.9 5.19 30.62 6.75 74.91 6.85 6.50 3:15 18.42 0.72 15.67 5.4814.39 1.92 8.86 5.23 28.19 95.66 63 8.37 6.40 CO₂ turned off, Added 5 mLhydrated white lime (4 grams total) 3:45 11.16 2.85 8.33 1.99 8.05 3.596.34 3.25 34.95 114.48 58.85 0.71 4:15 9.29 4.63 7.85 0.36 6.79 3.29 6.52.14 35.24 71.39 53.84 0.2

The solutions of Examples 13-17 along with blanks were placed in astainless steel bomb along with coupons 3-5 from the above test. Thebombs were place in an oven on a roller mill and the temperature wasadjusted to 450° F. The bombs were rolled under their own pressure forone day and the coupons analyzed pre-acid clean up and post acid cleanup. The results are tabulated in Table IVA&B. Looking at FIGS. 4A&B, thecoupons from Tests 13-15 are shown both pre-acid wash, FIG. 4A, and postacid wash, FIG. 4B. Looking at FIGS. 4C&D, the coupons from Tests 16-18are shown both pre-acid wash, FIG. 4C, and post acid wash, FIG. 4D.Looking at FIGS. 4E&F, the solutions of Tests 13-15 and Tests 16-18 areshown.

TABLE IVA Pre Acid Clean Up 450° F. Test Coupon Initial Final TimeDensity SA Corrosion Corrosion # # Test Solution Weight Weight (Days)(g/cm³) (in²) Wt. Loss (mpy) (lb/ft²/yr) Comments 13 1B Example 1320.4421 20.4518 1 7.85 4.372 −0.0097 −6.3 −026 Moderate amt. of scale 142B Example 14 20.9572 20.9720 1 7.85 4.372 −0.0148 −9.6 −0.39 Most scale15 3B Example 15 20.8526 20.8560 1 7.85 4.372 −0.0034 −2.2 −0.09 Smallamt. of scale 16 4B Example 16 20.4657 20.4591 1 7.85 4.372 0.0066 4.30.17 17 5B Example 17 21.0015 20.9964 1 7.85 4.372 0.0051 3.3 0.13 18 6BBlank 20.5335 20.5235 1 7.85 4.372 0.0100 6.5 0.26 mpy = (weight loss ingrams) * (22,300)/(Adt)

TABLE IVB Post Acid Clean Up 450° F. Initial Final Time Density SACorrosion Corrosion Test # Coupon # Test Solution Weight Weight (Days)(g/cm³) (in²) Wt. Loss (mpy) (lb/ft²/yr) Comments 13 1B Example 1320.4421 20.3836 1 7.85 4.372 0.0595 38.0 1.55 14 2B Example 14 20.957220.8969 1 7.85 4.372 0.0603 39.2 1.59 15 3B Example 15 20.8526 20.8322 17.85 4.372 0.0204 13.3 0.54 16 4B Example 16 20.4657 20.4492 1 7.854.372 0.0165 10.7 0.44 17 5B Example 17 21.0015 20.9882 1 7.85 4.3720.0133 8.6 0.35 18 6B Blank 20.5335 20.4992 1 7.85 4.372 0.0343 22.30.91 mpy = (weight loss in grams) * (22,300)/(Adt)

Coupons were added to the solutions of Examples 13-17 along with twoblanks and the solutions with the coupons were then run in an autoclaveat 500° F. and at a pressure of 5000 psi. The solutions were adjusted topH 10 with sodium hydroxide and 5 mL per 1100 mL of 20 wt. % Calciumhydroxide was added along with 1 g of NaS per 1100 mL. The results ofthe tests are tabulate in Table VA&B, which clearly shows thesignificant protection afforded the coupons by the compositions ofExamples 16 and 17. These solutions are particularly preferred becausethese solutions include an acid inhibitor, a scale inhibitor and asulfur scavenger, where the scale inhibitor is a salt of a phosphateester, the acid inhibitor includes a quinoline cationic surfactant andthe sulfur scavenger can be either a triazine-type sulfur scavenger or anon-triazine formaldehyde-amine reaction production. Looking at FIG. 5A,the Test 19 solutions of Example 13 are shown after 24 hours in theautoclave. Looking at FIG. 5B-D, the coupons 11-13 are shown immediatelyupon removal from the Test 19 solutions, prior to acid washing and afteracid washing, respectively. Looking at FIG. 5E, the Test 20 solutions ofExample 14 are shown after 24 hours in the autoclave. Looking at FIG.5F-H, the coupons 14-16 are shown immediately upon removal from the Test20 solutions, prior to acid washing and after acid washing,respectively. Looking at FIG. 5I, the Test 21 solutions of Example 15are shown after 24 hours in the autoclave. Looking at FIG. 5J-L, thecoupons 17-19 are shown immediately upon removal from the Test 21solutions, prior to acid washing and after acid washing, respectively.Looking at FIG. 5M, the Test 22 solutions of Example 16 are shown after24 hours in the autoclave. Looking at FIG. 5N-P, the coupons 20-22 areshown immediately upon removal from the Test 22 solutions, prior to acidwashing and after acid washing, respectively. Looking at FIG. 5Q, theTest 23 solutions of Example 17 are shown after 24 hours in theautoclave. Looking at FIG. 5R-T, the coupons 23-25 are shown immediatelyupon removal from the Test 23 solutions, prior to acid washing and afteracid washing, respectively. Looking at FIG. 5U, the Test 24 solutions ofBlank are shown after 24 hours in the autoclave. Looking at FIG. 5V-X,the coupons 26-28 are shown immediately upon removal from the Blanksolutions, prior to acid washing and after acid washing, respectively.Looking at FIG. 5W, the Test 25 solutions of Blank with 3.5 wt. %Seawater are shown after 24 hours in the autoclave. Looking at FIGS. 5Z,AA & AB, the coupons 29-30 are shown immediately upon removal from theTest 25 solutions, prior to acid washing and after acid washing,respectively.

TABLE VA Pre Acid Clean Up 500° F. Initial Final Time Density SACorrosion Average Corrosion Average Test # Coupon # Test Solution WeightWeight (Days) (g/cm³) (in²) Wt. Loss (mpy) (mpy) (lb/ft²/yr) (lb/ft²/yr)19 11 Example 13 21.994 22.0128 1 7.87 3.467 −0.0188 −15.4 −30.84 −0.62−1.25 19 12 Example 13 22.2818 22.3284 1 7.87 3.467 −0.0466 −38.1 −1.5519 13 Example 13 22.5425 22.5903 1 7.87 3.467 −0.0478 −39.1 −1.59 20 14Example 14 22.1137 22.1486 1 7.87 3.467 −0.0349 −28.5 −33.65 −1.16 −0.7420 15 Example 14 22.4739 22.5055 1 7.87 3.467 −0.0316 −25.8 −1.05 20 16Example 14 21.917 21.974  1 7.87 3.467 −0.057 −46.6 −1.89 21 17 Example15 22.3933 22.4389 1 7.87 3.467 −0.0456 −37.3 −40.05 −1.51 −1.63 21 18Example 15 22.2756 22.3229 1 7.87 3.467 −0.0473 −38.7 −1.57 21 19Example 15 22.8684 22.9225 1 7.87 3.467 −0.0541 −44.2 −1.80 22 20Example 16 22.6371 22.6479 1 7.87 3.467 −0.0108 −8.8 −9.40 −0.36 −0.3822 21 Example 16 22.7625 22.7743 1 7.87 3.467 −0.0118 −9.6 −0.39 22 22Example 16 22.8192 22.8311 1 7.87 3.467 −0.0119 −9.7 −0.40 23 23 Example17 22.1256 22.1389 1 7.87 3.467 −0.0133 −10.9 −10.82 −0.44 −0.44 23 24Example 17 22.112 22.1278 1 7.87 3.467 −0.0158 −12.9 −0.52 23 25 Example17 22.6595 22.6701 1 7.87 3.467 −0.0106 −8.7 −0.35 24 26 Blank-TestFluid 22.3819 22.3741 1 7.87 3.467 0.0078 6.4 8.99 0.26 0.37 24 27Blank-Test Fluid 22.3605 22.3515 1 7.87 3.467 0.009 7.4 0.30 24 28Blank-Test Fluid 22.1093 22.0931 1 7.87 3.467 0.0162 13.2 0.54 25 29Blank-3.5% Seawater 22.197 22.2694 1 7.87 3.467 −0.0724 −59.2 −51.20−2.41 −2.08 25 30 Blank-3.5% Seawater 22.6225 22.6754 1 7.87 3.467−0.0529 −43.2 −1.76

TABLE VB Post Acid Clean Up 500° F. Initial Final Time Density SACorrosion Average Corrosion Average Test # Coupon # Test Solution WeightWeight (Days) (g/cm³) (in{circumflex over ( )}2) Wt. Loss (mpy) (mpy)(lb/ft²/yr) (lb/ft²/yr) 19 11 Example 13 21.994 21.9594 1 7.87 3.4670.0346 28.3 27.16 1.15 1.10 19 12 Example 13 22.2818 22.2392 1 7.873.467 0.0426 34.8 1.42 19 13 Example 13 22.5425 22.52 1 7.87 3.4670.0225 18.4 0.75 20 14 Example 14 22.1137 22.0692 1 7.87 3.467 0.044536.4 29.99 1.48 1.22 20 15 Example 14 22.4739 22.4397 1 7.87 3.4670.0342 28.0 1.14 20 16 Example 14 21.917 21.8856 1 7.87 3.467 0.031425.7 1.04 21 17 Example 15 22.3933 22.3496 1 7.87 3.467 0.0437 35.734.98 1.45 1.42 21 18 Example 15 22.2756 22.2332 1 7.87 3.467 0.042434.7 1.41 21 19 Example 15 22.8684 22.8261 1 7.87 3.467 0.0423 34.6 1.4122 20 Example 16 22.6371 22.6325 1 7.87 3.467 0.0046 3.8  4.66 0.15 0.1922 21 Example 16 22.7625 22.7568 1 7.87 3.467 0.0057 4.7 0.19 22 22Example 16 22.8192 22.8124 1 7.87 3.467 0.0068 5.6 0.23 23 23 Example 1722.1256 22.1205 1 7.87 3.467 0.0051 4.2  6.02 0.17 0.24 23 24 Example 1722.112 22.1062 1 7.87 3.467 0.0058 4.7 0.19 23 25 Example 17 22.659522.6483 1 7.87 3.467 0.0112 9.2 0.37 24 26 Blank-Test Fluid 22.381922.3475 1 7.87 3.467 0.0344 28.1 29.31 1.14 1.19 24 27 Blank-Test Fluid22.3605 22.3243 1 7.87 3.467 0.0362 29.6 1.20 24 28 Blank-Test Fluid22.1093 22.0723 1 7.87 3.467 0.037 30.2 1.23 25 29 Blank-3.5% Seawater22.197 22.1573 1 7.87 3.467 0.0397 32.4 26.28 1.32 1.07 25 30 Blank-3.5%Seawater 22.6225 22.5979 1 7.87 3.467 0.0246 20.1 0.82

The data clearly shows the superior protection afforded by thecompositions of this invention that include a phosphate ester scaleinhibitor, a cationic acid inhibitor and a sulfur scavenger. Theprotection is so significantly improved that metals in contact withfluids including the corrosion control systems of this invention willhave significantly greater life times.

All references cited herein are incorporated by reference. While thisinvention has been described fully and completely, it should beunderstood that, within the scope of the appended claims, the inventionmay be practiced otherwise than as specifically described. Although theinvention has been disclosed with reference to its preferredembodiments, from reading this description those of skill in the art mayappreciate changes and modification that may be made which do not departfrom the scope and spirit of the invention as described above andclaimed hereafter.

We claim:
 1. An aqueous drilling fluid composition comprising: water,and effective amount of a corrosion control system including: from about1.25 ppm to about 5 wt. % of an anionic scale inhibitor selected fromthe group consisting of: (a) alkali metal, alkaline earth metal, ortransition metal salts of alkyl phosphate esters; (b) alkali metal,alkaline earth metal, or transition metal salts of alkoxy phosphateesters; (c) alkali metal, alkaline earth metal, or transition metalsalts of glycol phosphate esters; (d) alkali metal, alkaline earthmetal, or transition metal salts of alkylpolyols phosphate esters, and(e) mixtures or combinations thereof, from about 0.25 wt. % to about 10wt. % of a cationic acid inhibitor or dispersant, from about 0.1 wt. %of a noxious species inhibitor up to about a 10:1 ratio of the noxiousspecies inhibitor to noxious species in the fluid to be treated, andfrom about 1 to 10 lbs per barrel of a lime slurry or hot lime, wherethe effective amount is between about 0.1% v/v to about 5% v/v, wherethe system reduces or prevents corrosion of metallic surfaces in contactwith the aqueous drilling fluid composition, and where the aqueousdrilling fluid composition is effective over a temperature range betweenabout 100° F. and about 600° F.
 2. The composition of claim 1, furthercomprising: a density reduction additive, a shale inhibitor, and/or a pHmodifier selected from the group consisting of alkali hydroxides, alkalicarbonates, alkali bicarbonates, alkaline earth metal hydroxides,alkaline earth metal carbonates, alkaline earth metal bicarbonates andmixtures or combinations thereof.
 3. The composition of claim 2, whereinthe pH modifier is present in an amount sufficient to adjust thecomposition to a pH of about 10.0.
 4. The composition of claim 1,wherein: the cationic acid inhibitor comprises quaternary ammoniumsalts, salts of nitrogen bases, or mixtures or combinations thereof,where the salt is selected from the group consisting of chloride,bromide, iodide, dimethylsulfate, diethylsulfate, nitrite, hydroxide,alkoxides, and mixtures or combinations thereof, and the noxious speciesinhibitor or scavenger comprises aldehyde-amine adducts, triazines, ormixtures and combinations thereof.
 5. A corrosion control compositioncomprising: from about 1.25 ppm to about 5 wt. % of an anionic scaleinhibitor selected from the group consisting of: (a) alkali metal,alkaline earth metal, or transition metal salts of alkyl phosphateesters; (b) alkali metal, alkaline earth metal, or transition metalsalts of alkoxy phosphate esters; (c) alkali metal, alkaline earthmetal, or transition metal salts of glycol phosphate esters; (d) alkalimetal, alkaline earth metal, or transition metal salts of alkylpolyolsphosphate esters, and (e) mixtures or combinations thereof, from about0.25 wt. % to about 10 wt. % of a cationic acid inhibitor or dispersant,from about 0.1 wt. % of a noxious species inhibitor up to about a 10:1ratio of the noxious species inhibitor to noxious species in the fluidto be treated, and from about 1 to 10 lbs per barrel of a lime slurry orhot lime, where the composition reduces or prevents corrosion ofmetallic surfaces in contact with a fluid containing the compositionsystem and where the composition is effective over a temperature rangebetween about 100° F. and about 600° F.
 6. The composition of claim 5,further comprising: a density reduction additive, a shale inhibitor,and/or a pH modifier is selected from the group consisting of alkalihydroxides, alkali carbonates, alkali bicarbonates, alkaline earth metalhydroxides, alkaline earth metal carbonates, alkaline earth metalbicarbonates and mixtures or combinations thereof.
 7. The composition ofclaim 6, wherein the pH modifier is present in an amount sufficient toadjust the composition to a pH of about 10.0.
 8. The composition ofclaim 5, wherein the fluid comprises a drilling fluid, a completionfluid, production fluid, a fracturing fluid or a second oil recoveryfluid.
 9. The composition of claim 5, wherein: the cationic acidinhibitor comprises quaternary ammonium salts, salts of nitrogen bases,or mixtures or combinations thereof, where the salt is selected from thegroup consisting of chloride, bromide, iodide, dimethylsulfate,diethylsulfate, nitrite, hydroxide, alkoxides, and mixtures orcombinations thereof, and the noxious species inhibitor or scavengercomprises aldehyde-amine adducts, triazines, or mixtures or combinationsthereof.
 10. A water-base drilling fluid composition for use in drillingwells through a formation containing a clay which swells in the presenceof water, the drilling fluid comprising: (a) a weight material selectedfrom the group consisting of barite, hematite, iron oxide, calciumcarbonate, magnesium carbonate, and combinations thereof; (b) an anionicpolymer; (c) a suspending agent selected from the group consisting ofbentonite, polymeric suspending agent (xanthate gum or other gums),partially hydrolyzed polyacrylamide; and (d) an effective amount of acorrosion control system comprising: an anionic scale inhibitor selectedfrom the group consisting of: (1) alkali metal, alkaline earth metal, ortransition metal salts of alkyl phosphate esters; (2) alkali metal,alkaline earth metal, or transition metal salts of alkoxy phosphateesters; (3) alkali metal, alkaline earth metal, or transition metalsalts of glycol phosphate esters; (4) alkali metal, alkaline earthmetal, or transition metal salts of alkylpolyols phosphate esters, and(5) mixtures or combinations thereof, from about 0.25 wt. % to about 10wt. % of a cationic acid inhibitor or dispersant, from about 0.1 wt. %of a noxious species inhibitor up to about a 10:1 ratio of the noxiousspecies inhibitor to noxious species in the fluid to be treated, andfrom about 1 to 10 lbs per barrel of a lime slurry or hot lime, (e) ashale inhibitor, where the effective amount is between about 0.1% v/v toabout 5% v/v, where the system reduces or prevents corrosion of metallicsurfaces in contact with the fluid, and where the composition iseffective over a temperature range between about 100° F. and about 600°F.
 11. The composition of claim 10, further comprising: a densityreduction additive, and/or a pH modifier selected from the groupconsisting of alkali hydroxides, alkali carbonates, alkali bicarbonates,alkaline earth metal hydroxides, alkaline earth metal carbonates,alkaline earth metal bicarbonates and mixtures or combinations thereof.12. The composition of claim 11, wherein the pH modifier is present inan amount sufficient to adjust the composition to a pH of about 10.0.13. The composition of claim 10, wherein: the cationic acid inhibitorcomprises quaternary ammonium salts, salts of nitrogen bases, ormixtures or combinations thereof, where the salt is selected from thegroup consisting of chloride, bromide, iodide, dimethylsulfate,diethylsulfate, nitrite, hydroxide, alkoxides, and mixtures orcombinations thereof, and the noxious species inhibitor or scavengercomprises aldehyde-amine adducts, triazines, or mixtures or combinationsthereof.